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"value": "Accounting policies Year ended 31 December 2022 (a) General information Tullow Oil plc is a company incorporated and domiciled in the United Kingdom under the Companies Act 2006. The address of the registered o ce is Tullow Oil plc, Building 9, Chiswick Park, 566 Chiswick High Road, London W4 5XT. The primary activity of the Group is the discovery and production of oil and gas. (b) Adoption of new and revised standards New International Financial Reporting Standards adopted The Group has applied the following standards and amendments for the \ufb01rst time for their annual reporting period commencing 1 January 2022: - Onerous Contracts \u2013 Costs of Ful\ufb01lling a Contract \u2013 Amendments to IAS 37; - IFRS 9 Financial Instruments \u2013 Fees in the '10 per cent' test for derecognition of \ufb01nancial liabilities'; - Reference to Conceptual Framework \u2013 Amendments to IFRS 3; and - Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16. The amendments listed above did not have any impact on the amounts recognised in prior periods and are not expected to signi\ufb01cantly affect the current or future periods. Upcoming International Financial Reporting Standards not yet adopted Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for 31 December 2022 reporting periods and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions. (c) Changes in accounting policy The Group has revised its accounting policy in relation to the presentation of corporate income taxes in Gabon and C\u00f4te d\u2019Ivoire Production Sharing Contracts (PSCs). Under the terms of the PSCs the share of the pro\ufb01t oil which the government is entitled to is deemed to include the notional corporate income tax which is paid by the government on behalf of Tullow. From 1 January 2022 the notional corporate income tax is classi\ufb01ed as an income tax in accordance with IAS 12 Income taxes which has resulted in a gross up of revenue with a corresponding increase in income tax expense. In the previous years, the Revenues and Taxes from Gabon and C\u00f4te d\u2019Ivoire were presented on a net basis. This change has been implemented to more accurately represent the Group\u2019s income tax obligations in Gabon and C\u00f4te d\u2019Ivoire and to be more comparable with other entities in the sector. Prior period balances have been adjusted to conform with the same presentation. As a result of the change, revenue for the year ended 31 December 2021 increased from $1,273.2 million to $1,285.4 million, whilst income tax expense increased from $283.4 million to $295.5 million. There is no impact on pro\ufb01t/(loss) for the year from continuing activities nor on basic and diluted earnings per share. In addition, the restatement had no impact on reported net assets, cash \ufb02ows or total equity. Accordingly, an additional balance sheet as at 1 January 2020 has not been presented. Refer to Note 6. Other than the above, the Group\u2019s accounting policies are consistent with the prior year. (d) Basis of preparation The Financial Statements have also been prepared in accordance with UK-adopted international accounting standards (UK-adopted IFRSs) and International Financial Reporting Standards adopted pursuant to Regulation (EC) No. 1606/2002 as it applies in the European Union. The \ufb01nancial reporting framework that has been applied in the preparation of the parent company \ufb01nancial statements is applicable law and United Kingdom Accounting Standards, including FRS 101 \u201cReduced Disclosure Framework\u201d (United Kingdom Generally Accepted Accounting Practice). The Financial Statements have been prepared on the historical cost basis, except for derivative \ufb01nancial instruments and contingent consideration which have been measured at fair value which are carried at fair value less cost to sell. The Financial Statements are presented in US dollars and all values are rounded to the nearest $0.1 million, except where otherwise stated. The principal accounting policies adopted by the Group are set out below. Liquidity risk management and going concern Assessment period and assumptions The Directors consider the going concern assessment period to be up to 31 March 2024. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets and different outcomes on ongoing disputes or litigation. Management has applied the following oil price assumptions for the going concern assessment: Base Case: $84/bbl for 2023, $79/bbl for 2024; and Low Case: $70/bbl for 2023, $70/bbl for 2024. The Low Case includes, amongst other downside assumptions, a 5% production decrease compared to the Base Case. Accounting policies continued Year ended 31 December 2022 (d) Basis of preparation continued Liquidity risk management and going concern continued At 31 December 2022, the Group had $1.1 billion liquidity headroom consisting of c.$0.6 billion free cash and $0.5 billion available under the revolving credit facility. The Group\u2019s forecasts show that the Group will be able to operate within its current debt facilities and have sufficient \ufb01nancial headroom for the going concern assessment period under its Base Case and Low Case. Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Thus, they have adopted the going concern basis of accounting in preparing the year end result. (e) Basis of consolidation The consolidated Financial Statements incorporate the Financial Statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power over an investee entity, is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to use its power to affect its returns. The results of subsidiaries acquired or disposed of during the year are included in the Group income statement from the transaction date of acquisition, being the date on which the Group gains control, and will continue to be included until the date that control ceases. If the Group loses control over a subsidiary, it derecognises the related assets, liabilities, non-controlling interest and other components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised at fair value. All intra-Group transactions, balances, income and expenses are eliminated on consolidation. Where necessary, adjustments are made to the Financial Statements of subsidiaries to bring the accounting policies used into line with those used by the Group. Joint arrangements The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classi\ufb01ed as joint operations in accordance with IFRS 11. The Group accounts for its share of the results and assets and liabilities of these joint operations. In addition, where Tullow acts as operator to the joint operation, the gross liabilities and receivables (including amounts due to or from non-operating partners) of the joint operation are included in the Group\u2019s balance sheet. (f) Business combinations The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other assets are acquired. The consideration transferred for the acquisition comprises of: - Fair values of the assets transferred; - Liabilities incurred to the former owners of the acquired business; - Equity interests issued by the group; - Fair value of any asset or liability resulting from a contingent consideration arrangement; and - Fair value of any pre-existing equity interest in the subsidiary. The Group determines that it has acquired a business when the acquired set of activities and assets include an input and a substantive process that together signi\ufb01cantly contribute to the ability to create outputs. The acquired process is considered substantive if it is critical to the ability to continue producing outputs, and the inputs acquired include an organised workforce with the necessary skills, knowledge, or experience to perform that process or it signi\ufb01cantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without signi\ufb01cant cost, effort, or delay in the ability to continue producing outputs. Identi\ufb01able assets acquired and liabilities and contingent liabilities assumed when control is obtained over a business, and when an interest or an additional interest is acquired in a joint operation which is a business are, with limited exceptions, measured initially at their fair values at the acquisition date. Acquisition-related costs are expensed as incurred. The excess of the consideration transferred, amount of any non-controlling interest in the acquired entity, and acquisition-date fair value of any previous equity interest in the acquired entity over the fair value of the net identi\ufb01able assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net identi\ufb01able assets of the business acquired, the difference is recognised directly in pro\ufb01t or loss as a bargain purchase. (g) Revenue from contracts with customers Revenue from contracts with customers represents the sales value, net of VAT, of the Group\u2019s share of liftings in the year. Revenue is recognised when control of the goods or services are transferred to the customer at an amount that re\ufb02ects the consideration to which the Group expects to be entitled in exchange for those goods or services. The Group has concluded that it is the principal in all of its revenue arrangements since it controls the goods or services before transferring them to the customer. The crude oil produced by the upstream operations is sold to external customers. Revenue from the sale of crude oil is recognised at the point in time when control of the product is transferred to the customer, which is typically when goods are delivered, and title has passed. The transportation and shipping costs associated with the transfer of the product to the point of sale is recognised as a selling cost. Under the terms of the relevant production sharing arrangements, the Group is entitled to its participating share in the crude oil based on the Group\u2019s working interest. Revenue from contracts with customers is recognised based on the actual volumes sold to customers. No adjustments are made to revenue for any differences between volumes sold to customers and unsold volumes which the Group is entitled to sell based on its working interest. Revenue in respect of such volumes is only recognised when there is a transfer of output to the Group\u2019s customers. Differences between the volume which the Group is entitled to sell based on its working interest and the actual volumes that the Group has sold to customers are recognised as an under/overlift (note (g)) within cost of sales. Under the terms of the Production Sharing Contracts in Gabon and C\u00f4te d\u2019Ivoire, the Group is not required to pay any corporate income taxes. The share of the pro\ufb01t oil which the government is entitled to is deemed to include a portion representing the notional corporate income tax paid by the government on behalf of the contractors. This portion of notional corporate income tax is presented as an income tax expenses with a corresponding amount recognised in Revenue. The Group\u2019s sales of crude oil are priced based on the consideration speci\ufb01ed in contracts with customers with reference to quoted market prices in active markets, adjusted for a quality differential based on gravity of the crude oil sold relative to Brent. Invoices are typically paid on 30-60 day terms. For certain non-operated arrangements, the Group\u2019s stake is structured as a carried interest, in which all costs relating to the performance of petroleum operations are borne by the operator and other joint venture partners and are recovered upon production. The recognition of revenue is on net basis, where the Group only accounts for its share of pro\ufb01t oil. (h) Over/underlift Lifting or offtake arrangements for oil and gas produced in certain of the Group\u2019s jointly owned operations are such that each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative production less stock is underlift or overlift. Underlift and overlift are valued at market value and included within receivables and payables respectively. Movements during an accounting period are adjusted through cost of sales such that gross pro\ufb01t is recognised on an entitlements basis. (i) Inventories Inventories, other than oil products, are stated at the lower of cost and net realisable value. Cost is determined on a weighted average cost basis and comprises direct purchase costs. Net realisable value is determined by reference to prices existing at the balance sheet date, less estimated costs of completion and the estimated costs necessary to make the sale. Oil product is stated at net realisable value and changes in net realisable value are recognised in the income statement. (j) Foreign currencies The US dollar is the presentational currency of the Group. For the purpose of presenting consolidated \ufb01nancial statements, the assets and liabilities of the Group\u2019s non-US dollar-denominated entities are translated at exchange rates prevailing on the balance sheet date. Income and expense items are translated at the average exchange rate for the period. Currency translation adjustments arising on the restatement of opening net assets of non-US dollar subsidiaries, together with differences between the subsidiaries\u2019 results translated at average rates versus closing rates, are recognised in the statement of comprehensive income and expense and transferred to the foreign currency translation reserve. All resulting exchange differences are classi\ufb01ed as equity until disposal of the subsidiary. On disposal, the cumulative amounts of the exchange differences are recognised as income or expense. Transactions in foreign currencies are recorded at the rates of exchange ruling at the transaction dates. Monetary assets and liabilities are translated into functional currency at the exchange rate ruling at the balance sheet date, with a corresponding charge or credit to the income statement. However, exchange gains and losses arising on monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign operation, are recognised in the foreign currency translation reserve and recognised in pro\ufb01t or loss on disposal of the net investment. In addition, exchange gains and losses arising on long-term foreign currency borrowings which are a hedge against the Group\u2019s overseas investments are dealt with in reserves. Accounting policies continued Year ended 31 December 2022 (k) Intangible, exploration and evaluation assets and oil and gas assets The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Pre-licence costs are expensed in the period in which they are incurred. All licence acquisition, exploration and evaluation costs and directly attributable administration costs are initially capitalised in cost centres by well, \ufb01eld or exploration area, as appropriate. These costs are then written off as exploration costs in the income statement unless commercial reserves have been established or the determination process has not been completed and there are no indications of impairment. Exploration and evaluation assets are tested for impairment when reclassi\ufb01ed to development assets, or whenever facts and circumstances indicate impairment. An impairment loss is recognised for the amounts by which the exploration and evaluation assets\u2019 carrying amount exceeds their recoverable amount. The recoverable amount is the higher of the exploration and evaluation asset\u2019s fair value less cost to sell and their value in use. Once commercial reserves are found, exploration and evaluation assets are tested for impairment and transferred to development assets. No depreciation and/or amortisation is charged during the exploration and evaluation phase. All \ufb01eld development costs are capitalised as property, plant and equipment. Property, plant and equipment related to production activities is amortised in accordance with the Group\u2019s depletion and amortisation accounting policy. Cash consideration received on farm-down of exploration and evaluation assets is credited against the carrying value of the asset. The excess amount over the carrying value of the asset is recognised as a gain on disposal of exploration and evaluation assets in the statement of pro\ufb01t or loss. (l) Commercial reserves Commercial reserves are proven and probable oil and gas reserves, which are de\ufb01ned as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a speci\ufb01ed degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and probable reserves and a 50% statistical probability that it will be less. (m) Depletion and amortisation All expenditure carried within each \ufb01eld is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a \ufb01eld-by-\ufb01eld basis or by a group of \ufb01elds which are reliant on common infrastructure. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future \ufb01eld development costs required to recover the commercial reserves remaining. Changes in the estimates of commercial reserves or future \ufb01eld development costs are dealt with prospectively. (n) Impairment of property, plant and equipment The Group assesses at each reporting date whether there is an indication that an asset (or CGU) may be impaired. In assessing whether an impairment is required, the carrying value of the asset or CGU is compared with its recoverable amount. The recoverable amount is the higher of the asset\u2019s/CGU\u2019s fair value less costs of disposal (FVLCD) and value in use (VIU). Given the nature of the Group\u2019s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers or similar transactions are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment charges described below is VIU. The Group estimates VIU using a discounted cash \ufb02ow model. In order to discount the future cash \ufb02ows the Group calculates asset or CGU-speci\ufb01c discount rates. The discount rates are based on an assessment of a relevant peer group\u2019s post-tax weighted average cost of capital (WACC). The post-tax WACC is subsequently grossed up to a pre-tax rate. The Group then deducts any exploration risk premium which is implicit within a peer group\u2019s WACC and subsequently applies additional country risk premium for all CGUs, an element of which is determined by whether the assets are onshore or offshore. Where there is evidence of economic interdependency between \ufb01elds, such as common infrastructure, the \ufb01elds are grouped as a single CGU for impairment purposes. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the income statement, net of any amortisation that would have been charged since the impairment. (o) Decommissioning Provision for decommissioning is recognised in full when the related facilities are installed. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of decommissioning, discounted to its net present value using a risk-free rate, and is re-assessed each year in accordance with local conditions and requirements. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. The unwinding of the discount on the decommissioning provision is included as a \ufb01nance cost. (p) Property, plant and equipment \u2013 non-oil and gas assets Property, plant and equipment is stated in the balance sheet at cost less accumulated depreciation and any recognised impairment loss. Depreciation on property, plant and equipment other than production assets is provided at rates calculated to write off the cost less the estimated residual value of each asset on a straight-line basis over its expected useful economic life of between three and ten years. (q) Borrowing costs Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale. All other \ufb01nance costs, which include interest on borrowings calculated using the effective interest method as described in paragraph (aa), obligations under \ufb01nance leases, the unwinding effect of discounting provisions and exchange differences, are recognised in the income statement in the period in which they are incurred. (r) Share issue expenses and share premium account Costs of share issues are written off against the premium arising on the issues of share capital. (s) Taxation Current and deferred tax, including UK corporation tax and overseas corporation tax, are provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred corporation tax is recognised on all temporary differences that have originated but not reversed at the balance sheet date where transactions or events that result in an obligation to pay more, or right to pay less, tax in the future have occurred at the balance sheet date. Deferred tax assets are recognised only to the extent that it is considered more likely than not that there will be suitable taxable pro\ufb01ts from which the underlying temporary differences can be deducted. Deferred tax is measured on a non-discounted basis. Deferred tax is provided on temporary differences arising on acquisitions that are categorised as business combinations. Deferred tax is recognised at acquisition as part of the assessment of the fair value of assets and liabilities acquired. Any deferred tax is charged or credited in the income statement as the underlying temporary difference is reversed. Petroleum revenue tax (PRT) is treated as an income tax and deferred PRT is accounted for under the temporary difference method. UK PRT refunds are included in the income statement and is taxable for UK corporation tax. (t) Pensions Contributions to the Group\u2019s de\ufb01ned contribution pension schemes are charged to operating pro\ufb01t on an accrual basis. (u) Derivative \ufb01nancial instruments The Group uses derivative \ufb01nancial instruments, such as forward currency contracts and commodity options contracts, to hedge its foreign currency risks and commodity price risks respectively. Derivatives are recognised initially at fair value at the date a derivative contract is entered into and are subsequently remeasured to their fair value at each reporting date. The resulting gain or loss is recognised in pro\ufb01t or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in pro\ufb01t or loss depends on the nature of the hedge relationship. For the purpose of hedge accounting, hedges are classi\ufb01ed as: - fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability or an unrecognised \ufb01rm commitment; - cash \ufb02ow hedges when hedging the exposure to variability in cash \ufb02ows that is either attributable to a particular risk; - associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an unrecognised \ufb01rm commitment; and - hedges of a net investment in a foreign operation. At the inception of a hedge relationship, the Group formally designates and documents the hedge relationship to which it wishes to apply hedge accounting. Accounting policies continued Year ended 31 December 2022 (u) Derivative \ufb01nancial instruments continued The documentation includes identi\ufb01cation of the hedging instrument, the hedged item, the nature of the risk being hedged and how the Group will assess whether the hedging relationship meets the hedge effectiveness requirements (including the analysis of sources of hedge ineffectiveness and how the hedge ratio is determined). A hedging relationship quali\ufb01es for hedge accounting if it meets all of the following effectiveness requirements: - There is \u2018an economic relationship\u2019 between the hedged item and the hedging instrument; - The effect of credit risk does not \u2018dominate the value changes\u2019 that result from that economic relationship; and - The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the time value hedge reserve. If the hedged item is transaction related, the time value is reclassi\ufb01ed to pro\ufb01t or loss when the hedged item affects pro\ufb01t or loss. If the hedged item is time-period related, then the amount accumulated in the time value hedge reserve is reclassi\ufb01ed to pro\ufb01t or loss on a rational basis. Those reclassi\ufb01ed amounts are recognised in pro\ufb01t or loss in the same line as the hedged item. Furthermore, if the Group expects that some or all of the loss accumulated in hedging reserve will not be recovered in the future, that amount is immediately reclassi\ufb01ed to pro\ufb01t or loss. Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the \ufb01nancial asset to that asset\u2019s net carrying amount. Cash \ufb02ow hedges The effective portion of the gain or loss on the hedging instrument is recognised in OCI in the cash \ufb02ow hedge reserve, while any ineffective portion is recognised immediately in the statement of pro\ufb01t or loss. The cash \ufb02ow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. The Group uses oil option contracts for its exposure to volatility of Dated Brent prices. The ineffective portion relating to option contracts is recognised as gain or loss on hedging instruments in the Group income statement. Amounts previously recognised in other comprehensive income and accumulated in equity are reclassi\ufb01ed to pro\ufb01t or loss in the periods when the hedged item affects pro\ufb01t or loss, in the same line as the recognised hedged item. Cash \ufb02ow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the hedging instrument is sold, terminated or exercised without replacement or rollover. When cash \ufb02ow hedge accounting is discontinued, amounts previously recognised within other comprehensive income remain in equity until the forecast transaction occurs and are reclassi\ufb01ed to pro\ufb01t or loss or transferred to the initial carrying amount of a non-\ufb01nancial asset or liability as above. If the forecast transaction is no longer expected to occur, amounts previously recognised within other comprehensive income will be immediately reclassi\ufb01ed to pro\ufb01t or loss. (v) Convertible bonds Where bonds issued with certain conversion rights are identi\ufb01ed as compound instruments, the liability and equity components are separately recognised. The fair value of the liability component on initial recognition is calculated by discounting the contractual stream of future cash \ufb02ows using the prevailing market interest rate for similar non-convertible debt. The difference between the fair value of the liability component and the fair value of the whole instrument is recorded as equity. Transaction costs are apportioned between the liability and the equity components of the instrument based on the amounts initially recognised. The liability component is subsequently measured at amortised cost using the effective interest rate method, in line with our other \ufb01nancial liabilities. The equity component is not remeasured. On conversion of the instrument, equity is issued and the liability component is derecognised. The original equity component recognised at inception remains in equity. No gain or loss is recognised on conversion. In an event of a repayment of the liability component, the original equity component is transferred to retained earnings. (w) Leases On inception of a contract, the Group assesses whether the contract is, or contains, a lease. The contract is, or contains, a lease if it conveys the right to control the use of an identi\ufb01ed asset for a period of time in exchange for consideration. To determine whether the contract conveys the right to control the use of an identi\ufb01ed asset, the Group assesses whether the contract involves the use of an identi\ufb01ed asset, the Group has the right to obtain substantially all of the economic bene\ufb01ts from the use of the asset throughout the period of use, and the Group has the right to direct the use of the asset. i) Lessee accounting Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability, in case of Joint operation, adjusted for any amount receivable from Joint Venture Partners and any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs required to remove or restore the underlying asset, less any lease incentives received. The right-of-use asset is depreciated over the shorter of the asset\u2019s useful life and the lease term on a straight-line basis, or applying the unit of production method, and the Joint Venture receivable is allocated against the monthly Joint Venture billing cycle. The initial measurement of the corresponding lease liability is at the present value of the lease payments that are not paid at the lease commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Group\u2019s incremental borrowing rate. The lease payments include \ufb01xed payments, less any lease incentive receivable, variable leases payments based on an index or rate, and amounts expected to be payable by the lessee under residual value guarantees. The lease liability is subsequently measured at amortised cost using the effective interest method. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the Group\u2019s estimate of the amount expected to be payable under a residual value guarantee or if the Group changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset or is recorded in pro\ufb01t or loss if the carrying amount of the right-of-use asset has been reduced to zero. The Group has elected not to recognise right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less, and leases of low-value assets with a value of $5,000. Over the course of a lease contract, there will be taxable timing differences that could give rise to deferred tax, subject to local tax laws and regulations. Extension and termination options are included in a number of property and equipment leases across the Group. These are used to maximise operational \ufb02exibility in terms of managing the assets used in the Group\u2019s operations. The majority of extension and termination options held are exercisable only by the Group and not by the respective lessor. (x) Share-based payments The Group has applied the requirements of IFRS 2 Share-based Payments. The Group has share-based awards that are equity settled and cash settled as de\ufb01ned by IFRS 2. The fair value of the equity settled awards has been determined at the date of grant of the award allowing for the effect of any market-based performance conditions. This fair value, adjusted by the Group\u2019s estimate of the number of awards that will eventually vest as a result of non-market conditions, is expensed uniformly over the vesting period. The fair values were calculated using a binomial option pricing model with suitable modi\ufb01cations to allow for employee turnover after vesting and early exercise. Where necessary, this model is supplemented with a Monte Carlo model. The inputs to the models include: the share price at date of grant; exercise price; expected volatility; expected dividends; risk-free rate of interest; and patterns of exercise of the plan participants. For cash settled awards, a liability is recognised for the goods or service acquired, measured initially at the fair value of the liability. At each balance sheet date until the liability is settled, and at the date of settlement, the fair value of the liability is remeasured, with any changes in fair value recognised in the income statement. Accounting policies continued Year ended 31 December 2022 (y) Financial assets At initial recognition, the Group measures a \ufb01nancial asset at its fair value plus, in the case of a \ufb01nancial asset not at fair value through pro\ufb01t or loss (FVPL), transaction costs that are directly attributable to the acquisition of the \ufb01nancial asset. Transaction costs of \ufb01nancial assets carried at FVPL are expensed in pro\ufb01t or loss. The subsequent measurement of \ufb01nancial assets depends on their classi\ufb01cation, as set out overleaf. i) Financial assets measured at amortised cost Assets are subsequently classi\ufb01ed and measured at amortised cost when the business model of the Company is to collect contractual cash \ufb02ows and the contractual terms give rise to cash \ufb02ows that are solely payments of principal and interest. These assets are carried at amortised cost using the effective interest method if the time value of money is signi\ufb01cant. Gains and losses are recognised in pro\ufb01t or loss when the assets are derecognised, modi\ufb01ed or impaired. This category of \ufb01nancial assets includes trade and other receivables. Financial assets measured at amortised cost include trade receivables, loans and other receivables that have \ufb01xed or determinable payments that are not quoted in an active market. Loans and receivables are measured at amortised cost using the effective interest method, less any impairment. Interest income is recognised by applying the effective interest rate, except for short-term receivables when the recognition of interest would be immaterial. ii) Financial asset measured at fair value through other comprehensive income Assets are subsequently classi\ufb01ed and measured at fair value through other comprehensive income when the business model of the Company is to collect contractual cash \ufb02ows and sell the \ufb01nancial assets, and the contractual cash \ufb02ows represent solely payments of principal and interest. iii) Financial assets measured at fair value through pro\ufb01t or loss Financial assets are classi\ufb01ed as measured at fair value through pro\ufb01t or loss when the asset does not meet the criteria to be measured at amortised cost or fair value through other comprehensive income. These assets are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category. As at 31 December 2022, the Group does not have any \ufb01nancial assets classi\ufb01ed at fair value through pro\ufb01t or loss or other comprehensive income. Regular way purchases and sales of \ufb01nancial assets are recognised on trade date, being the date on which the Group commits to purchase or sell the asset. Financial assets are derecognised when the rights to receive cash \ufb02ows from the \ufb01nancial assets have expired or have been transferred and the Group has transferred substantially all the risks and rewards of ownership. Impairment of trade and joint venture receivables The Group applies the IFRS 9 simpli\ufb01ed approach to measuring expected credit losses which uses a lifetime expected loss allowance for all trade receivables. To measure the expected credit losses, trade receivables have been grouped based on shared credit risk characteristics and days past due. The expected loss rates are based on the payment pro\ufb01les of sales over the historical period and the corresponding historical credit losses experienced within this period. These rates are then applied to the gross carrying amount of the receivable to arrive at the loss allowance for the period. Based on Management assessment the credit loss in trade receivables and joint venture receivable as at 31 December 2022 would be immaterial; therefore, in line with IFRS 9, no impairment was recognised (2021: $nil). In order to minimise the risk of default, credit risk is managed on a Group basis (note 18). (z) Cash and cash equivalents Cash and cash equivalents comprise cash at bank, demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insigni\ufb01cant risk of changes in value. (aa) Effective interest method The effective interest method is a method of calculating the amortised cost of a \ufb01nancial asset and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees on points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the \ufb01nancial asset, or, where appropriate, a shorter period. Income is recognised on an effective interest basis for debt instruments other than those \ufb01nancial assets classi\ufb01ed as at FVTPL. (ab) Financial liabilities The measurement of \ufb01nancial liabilities is determined by the initial classi\ufb01cation. i) Financial liabilities at fair value through pro\ufb01t or loss: Those balances that meet the de\ufb01nition of being held for trading are measured at fair value through pro\ufb01t or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognised in the income statement. ii) Financial liabilities measured at amortised cost: All \ufb01nancial liabilities not meeting the criteria of being classi\ufb01ed at fair value through pro\ufb01t or loss are classi\ufb01ed as \ufb01nancial liabilities measured at amortised cost. The instruments are initially recognised at its fair value net of transaction costs that are directly attributable to the issue of \ufb01nancial liability. Subsequent to initial recognition, \ufb01nancial liabilities are measured at amortised cost using the effective interest method. Trade payables and borrowings fall under this category of \ufb01nancial instruments. As at 31 December 2022 all \ufb01nancial liabilities are measured at amortised cost. The Group derecognises a \ufb01nancial liability when it is extinguished, i.e. when the obligation speci\ufb01ed in the contract is discharged or cancelled or expires. A substantial modi\ufb01cation of the terms of an existing \ufb01nancial liability or a part of it is accounted for as an extinguishment of the original \ufb01nancial liability and the recognition of a new \ufb01nancial liability. Offsetting of \ufb01nancial instruments: Financial assets and \ufb01nancial liabilities are offset and the net amount is reported in the consolidated statement of \ufb01nancial position if there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis, to realise the assets and settle the liabilities simultaneously. (ac) Equity instruments Equity instruments are classi\ufb01ed according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities. Equity instruments issued by the Group are recorded at the proceeds received, net of direct issue costs. (ad) Insurance proceeds Insurance proceeds related to lost production under the Business Interruption insurance policy are recorded as other operating income in the income statement. Proceeds related to compensation for incremental operating costs under the Business Interruption and Hull and Machinery insurance policies are recorded within the operating costs line of cost of sales. Proceeds related to compensation for capital costs under insurance policies are recorded within pro\ufb01t and loss with corresponding cost for replacement asset as additions to property, plant and equipment. Insurance proceeds are recognised at the point when the realisation of income is virtually certain. (ae) Provisions Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an out\ufb02ow of resources embodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Onerous contracts If the Group has a contract that is onerous, the present obligation under the contract is recognised and measured as a provision. However, before a separate provision for an onerous contract is established, the Group recognises any impairment loss that has occurred on assets dedicated to that contract. An onerous contract is a contract under which the unavoidable costs (i.e., the costs that the Group cannot avoid because it has the contract) of meeting the obligations under the contract exceed the economic bene\ufb01ts expected to be received under it. The unavoidable costs under a contract re\ufb02ect the least net cost of exiting from the contract, which is the lower of the cost of ful\ufb01lling it and any compensation or penalties arising from failure to ful\ufb01l it. The cost of ful\ufb01lling a contract comprises the costs that relate directly to the contract (i.e., both incremental costs and an allocation of costs directly related to contract activities). Accounting policies continued Year ended 31 December 2022 (af) Critical accounting judgements The Group assesses critical accounting judgements annually. The following are the critical judgements, apart from those involving estimations which are dealt with in policy (ag), that the Directors have made in the process of applying the Group\u2019s accounting policies and that have the most signi\ufb01cant effect on the amounts recognised in the Financial Statements. Carrying value of intangible exploration and evaluation assets (note 9) The amounts for intangible exploration and evaluation assets represent active exploration projects. These amounts will be written off to the income statement as exploration costs unless commercial reserves are established or the determination process is not completed and there are no indications of impairment in accordance with the Group\u2019s accounting policy. The process of determining whether there is an indicator for impairment or calculating the impairment requires critical judgement. The key areas in which Management has applied judgement and estimation are as follows: the Group\u2019s intention to proceed with a future work programme for a prospect or licence; the likelihood of licence renewal or extension; the assessment of whether sufficient data exist to indicate that, although a development in the speci\ufb01c area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale; and the success of a well result or geological or geophysical survey. Details on impact of these key estimates using sensitivities applied to impairment models can be found in note 9. The most material area where judgement was applied during 2022 was in the assessment of the value in use (VIU) of the Kenyan CGU and assessing the likelihood of recovery of the net book value of the asset. A trigger for potential impairment reversal was identi\ufb01ed following the Group\u2019s increase in long-term oil price assumption resulting in an increase in the underlying value of the project. Due to the stage of this project being pre-\ufb01nal investment decision (FID) and only having 2C resources booked, the VIU assessment required estimation and judgement in a number of different aspects including oil prices differentials, uncontracted cost pro\ufb01les and certain \ufb01scal terms. Furthermore, the Group has identi\ufb01ed the following estimation uncertainties, which require judgement, in respect to the Group\u2019s ability to realise the estimated VIU; receiving an acceptable offer from a strategic partner, obtaining \ufb01nancing for the project and government deliverables. These items require satisfactory resolution before the Group can take FID. Due to the binary nature of these uncertainties the Group was unable to either adjust the cash \ufb02ows or discount rate appropriately. It has therefore used its judgement and assessed the probability of achieving FID and therefore the recognition of commercial reserves. This probability was applied to the VIU to determine a risk adjusted VIU and compared against the net book value of the asset. Based on this there is no impairment or impairment reversal as at 31 December 2022. Should the uncertainties around the project be resolved there will be a reversal of previously recognised impairment. However, if the uncertainties are not resolved there will be an impairment of $253 million. Lease accounting (note 19) Discount rate The Group has assessed the appropriate incremental borrowing rate applicable for each contract. Management has applied the practical expedient which allows for the adoption of a portfolio approach, where a single discount rate for a portfolio of leases with similar characteristics can be applied. As the Group has external borrowings with a consortium of lenders, these are considered the best reference for the incremental borrowing rate for the Group. The weighted average cost of those borrowings is considered to the Group's 'all in rate', at the lease commencement date if the interest rate implicit in the lease is not readily determinable. As at 31 December 2022, the Group's incremental borrowing rate was 9.82%. Determination of the lease term Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. Extension and termination options are included in a number of property and equipment leases across the Group. These are used to maximise operational \ufb02exibility in terms of managing the assets used in the Group\u2019s operations. For leases relating to Joint Venture operations where there is an option to extend, the Group will only proceed after it has received Joint Venture approval to extend. At the inception of new leases in relation to joint arrangements they do not include any period covered by an extension option in the lease term because they cannot be reasonably certain that approval from the other venturers can be obtained. The majority of extension and termination options held are exercisable only by the Group and not by the respective lessor. Fair valuation of additional interest acquired in Ghana assets (note 15) The additional interest acquired in the Ghana assets has been recorded at fair value as required under IFRS 3. The property, plant and equipment acquired through the business combination has been recognised at the fair value based on the net present value of the discounted future cash \ufb02ows. Signi\ufb01cant inputs to the valuation include short- and long-term commodity prices, reserve estimates, production volume pro\ufb01les, planned development expenditure, cost pro\ufb01les and discount rates, and are consistent with those applied by the management when testing assets for impairments. (ag) Key sources of estimation uncertainty The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a signi\ufb01cant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next \ufb01nancial year, are discussed below. Carrying value of property, plant and equipment (note 10) Management performs impairment reviews on the Group\u2019s property, plant and equipment assets at least annually with reference to indicators in IAS 36 Impairment of Assets. Where indicators of impairments or impairment reversals are present and an impairment or impairment reversal test is required, the calculation of the recoverable amount requires estimation of future cash \ufb02ows within complex impairment models. Key assumptions and estimates in the impairment models relate to: commodity prices assumptions, pre-tax discount rates, commercial reserves and the related cost pro\ufb01les. Proven and probable reserves are estimates of the amount of oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its reserves using standard recognised evaluation techniques. The estimate is reviewed at least annually by Management and by independent consultants. Proven and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of remaining recoverable reserves and the proportion of the gross reserves which are attributable to host governments under the terms of the Production Sharing Contracts. Future development costs are estimated taking into account the level of development required to produce the reserves by reference to operators, where applicable, and internal engineers. Net entitlement reserves estimates are subsequently calculated using the current oil price and cost recovery assumptions, in line with the relevant agreements. Changes in reserves as a result of factors such as production cost, recovery rates, grade of reserves or oil and gas prices could impact the depletion rates, carrying value of assets (refer to the Commercial Reserves and Contingent Resources Summary on page 176). The estimation applied by Management to the exploration risk premium adjustment to its impairment discount rates, estimated future commodity prices and forecast cash \ufb02ows on the TEN asset would have the most material impact on the 2022 Financial Statements should Management have concluded differently. Details on the impact of these key estimates and judgements using sensitivity applied to impairment models can be found in note 10. Uncertain tax treatments The Group is subject to various material claims which arise in the ordinary course of its business in various jurisdictions, including cost recovery claims, claims from regulatory bodies and both corporate income tax and indirect tax claims. The Group is in formal dispute proceedings regarding a number of these tax claims. The resolution of tax positions, through negotiation with the relevant tax authorities or litigation, can take several years to complete. In assessing whether these claims should be provided for in the Financial Statements, Management has considered them in the context of the applicable laws and relevant contracts for the countries concerned. Management has applied judgement in assessing the likely outcome of the claims and has estimated the \ufb01nancial impact based on external tax and legal advice and prior experience of such claims. Due to the uncertainty of such tax items, it is possible that on conclusion of an open tax matter at a future date the outcome may differ signi\ufb01cantly from Management\u2019s estimate. If the Group was unsuccessful in defending itself from all of these claims, the result would be additional liabilities of $1,024.0 million (2021: $1,025.5 million) which includes $32.4 million of interest and penalties (2021: $33.6 million). Provisions of $106.4 million (2021: $127.9 million) are included in income tax payable ($70.6 million (2021: $34.1 million)), deferred tax liability ($nil (2021:41.0 million)), and provisions ($35.8 million (2021: $52.8 million)). Where these matters relate to expenditure which is capitalised within Intangible Exploration and Evaluation Assets and Property, Plant and Equipment, any difference between the amounts accrued and the amounts settled is capitalised within the relevant asset balance, subject to applicable impairment indicators. Where these matters relate to producing activities or historical issues, any differences between the accrued and settled amounts are taken to the group income statement. The provisions and contingent liabilities relating to these disputes have decreased following the conclusion of tax authority challenges and matters lapsing under the statute of limitations, but have increased, following new claims being initiated and extrapolation of exposures through to 31 December 2022, giving rise to an overall decrease in provision of $21.5 million and decrease in contingent liability of $1.5 million. Accounting policies continued Year ended 31 December 2022 (ag) Key sources of estimation uncertainty continued Ghana tax assessments In October 2021, Tullow Ghana Limited (TGL) \ufb01led a Request for Arbitration with the International Chamber of Commerce (\u201cICC\u201d) disputing the $320 million branch pro\ufb01ts remittance tax (BPRT) assessment issued as part of the direct tax audit for the \ufb01nancial years 2014 to 2016. The Ghana Revenue Authority (GRA) is seeking to apply BPRT under a law which the Group considers is not applicable to TGL, since it falls outside the tax regime provided for in the Petroleum Agreements and relevant double tax treaties. The parties have agreed a procedural timetable for the arbitration under which the \ufb01rst Tribunal hearing will be held in October 2023. In December 2022, TGL received a $190.5 million corporate income tax assessment and payment demand from the GRA relating to the disallowance of loan interest for the \ufb01nancial years 2010 to 2020. The Group has previously disclosed assessments by the GRA relating to the same issue; this revised assessment supersedes all previous claims. The Group considers the assessment to breach TGL\u2019s rights under its Petroleum Agreements. In February 2023, TGL \ufb01led a Request for Arbitration with the ICC, disputing the assessment with the suspension of TGL\u2019s obligation to pay any amount in relation to the assessment until the dispute is formally resolved. In December 2022, TGL received a $196.5 million corporate income tax assessment and payment demand from the GRA relating to proceeds received by Tullow during the \ufb01nancial years 2016 to 2019 under Tullow\u2019s corporate Business Interruption Insurance policy. The Group considers the assessment to breach TGL\u2019s rights under its Petroleum Agreements. In February 2023, TGL \ufb01led a Request for Arbitration to the ICC, disputing the assessment with the suspension of TGL\u2019s obligation to pay any amount in relation to the assessment until the dispute is formally resolved. The Group continues to engage with the Government of Ghana with the aim of resolving all tax disputes on a mutually acceptable basis. Bangladesh litigation The National Board of Revenue (NBR) is seeking to disallow $118 million of tax relief in respect of development costs incurred by Tullow Bangladesh Limited (TBL). The NBR subsequently issued a payment demand to TBL in February 2020 for Taka 3,094 million (c.$37 million) requesting payment by 15 March 2020. However, under the Production Sharing Contract (PSC), the Government is required to indemnify TBL against all taxes levied by any public authority, and the share of production paid to Petrobangla (PB), Bangladesh\u2019s national oil company, is deemed to include all taxes due which PB is then obliged to pay to the NBR. TBL sent the payment demand to PB and the Government requesting the payment or discharge of the payment demand under their respective PSC indemnities. On 14 June 2021, TBL issued a formal notice of dispute under the PSC to the Government and PB. A further request for payment was received from NBR on 28 October 2021 demanding settlement by 15 November 2021. Arbitration proceedings were initiated under the PSC on 29 December 2021. A procedural hearing was held on 28 June 2022 which set the timetable for the process going forward. The \ufb01rst submissions have been made in October 2022 with the \ufb01rst Tribunal hearing scheduled for May 2024. Other items Other items totalling $280.0 million (2021: 547.5 million) comprise exposures in respect of claims for corporation tax in respect of disallowed expenditure or withholding taxes that are either currently under discussion with the tax authorities or which arise in respect of known issues for periods not yet under audit. Timing of cash \ufb02ows While it is not possible to estimate the timing of tax cash \ufb02ows in relation to possible outcomes with certainty, Management anticipates that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments. ",
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"fact-345": {
"value": "Accounting policies Year ended 31 December 2022 (a) General information Tullow Oil plc is a company incorporated and domiciled in the United Kingdom under the Companies Act 2006. The address of the registered o ce is Tullow Oil plc, Building 9, Chiswick Park, 566 Chiswick High Road, London W4 5XT. The primary activity of the Group is the discovery and production of oil and gas. (b) Adoption of new and revised standards New International Financial Reporting Standards adopted The Group has applied the following standards and amendments for the \ufb01rst time for their annual reporting period commencing 1 January 2022: - Onerous Contracts \u2013 Costs of Ful\ufb01lling a Contract \u2013 Amendments to IAS 37; - IFRS 9 Financial Instruments \u2013 Fees in the '10 per cent' test for derecognition of \ufb01nancial liabilities'; - Reference to Conceptual Framework \u2013 Amendments to IFRS 3; and - Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16. The amendments listed above did not have any impact on the amounts recognised in prior periods and are not expected to signi\ufb01cantly affect the current or future periods. Upcoming International Financial Reporting Standards not yet adopted Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for 31 December 2022 reporting periods and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions. (c) Changes in accounting policy The Group has revised its accounting policy in relation to the presentation of corporate income taxes in Gabon and C\u00f4te d\u2019Ivoire Production Sharing Contracts (PSCs). Under the terms of the PSCs the share of the pro\ufb01t oil which the government is entitled to is deemed to include the notional corporate income tax which is paid by the government on behalf of Tullow. From 1 January 2022 the notional corporate income tax is classi\ufb01ed as an income tax in accordance with IAS 12 Income taxes which has resulted in a gross up of revenue with a corresponding increase in income tax expense. In the previous years, the Revenues and Taxes from Gabon and C\u00f4te d\u2019Ivoire were presented on a net basis. This change has been implemented to more accurately represent the Group\u2019s income tax obligations in Gabon and C\u00f4te d\u2019Ivoire and to be more comparable with other entities in the sector. Prior period balances have been adjusted to conform with the same presentation. As a result of the change, revenue for the year ended 31 December 2021 increased from $1,273.2 million to $1,285.4 million, whilst income tax expense increased from $283.4 million to $295.5 million. There is no impact on pro\ufb01t/(loss) for the year from continuing activities nor on basic and diluted earnings per share. In addition, the restatement had no impact on reported net assets, cash \ufb02ows or total equity. Accordingly, an additional balance sheet as at 1 January 2020 has not been presented. Refer to Note 6. Other than the above, the Group\u2019s accounting policies are consistent with the prior year. (d) Basis of preparation The Financial Statements have also been prepared in accordance with UK-adopted international accounting standards (UK-adopted IFRSs) and International Financial Reporting Standards adopted pursuant to Regulation (EC) No. 1606/2002 as it applies in the European Union. The \ufb01nancial reporting framework that has been applied in the preparation of the parent company \ufb01nancial statements is applicable law and United Kingdom Accounting Standards, including FRS 101 \u201cReduced Disclosure Framework\u201d (United Kingdom Generally Accepted Accounting Practice). The Financial Statements have been prepared on the historical cost basis, except for derivative \ufb01nancial instruments and contingent consideration which have been measured at fair value which are carried at fair value less cost to sell. The Financial Statements are presented in US dollars and all values are rounded to the nearest $0.1 million, except where otherwise stated. The principal accounting policies adopted by the Group are set out below. Liquidity risk management and going concern Assessment period and assumptions The Directors consider the going concern assessment period to be up to 31 March 2024. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets and different outcomes on ongoing disputes or litigation. Management has applied the following oil price assumptions for the going concern assessment: Base Case: $84/bbl for 2023, $79/bbl for 2024; and Low Case: $70/bbl for 2023, $70/bbl for 2024. The Low Case includes, amongst other downside assumptions, a 5% production decrease compared to the Base Case. Accounting policies continued
Year ended 31 December 2022
(d) Basis of preparation continued
Liquidity risk management and going concern continued
At 31 December 2022, the Group had $1.1 billion liquidity headroom consisting of c.$0.6 billion free cash and $0.5 billion available under
the revolving credit facility.
The Group\u2019s forecasts show that the Group will be able to operate within its current debt facilities and have sufficient \ufb01nancial
headroom for the going concern assessment period under its Base Case and Low Case. Based on the analysis above, the Directors
have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future.
Thus, they have adopted the going concern basis of accounting in preparing the year end result.
(e) Basis of consolidation
The consolidated Financial Statements incorporate the Financial Statements of the Company and entities controlled by the Company
(its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power over an investee entity, is
exposed, or has rights, to variable returns from its involvement with the investee and has the ability to use its power to affect its returns.
The results of subsidiaries acquired or disposed of during the year are included in the Group income statement from the transaction
date of acquisition, being the date on which the Group gains control, and will continue to be included until the date that control ceases.
If the Group loses control over a subsidiary, it derecognises the related assets, liabilities, non-controlling interest and other
components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised at fair
value. All intra-Group transactions, balances, income and expenses are eliminated on consolidation.
Where necessary, adjustments are made to the Financial Statements of subsidiaries to bring the accounting policies used into line
with those used by the Group.
Joint arrangements
The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are
classi\ufb01ed as joint operations in accordance with IFRS 11. The Group accounts for its share of the results and assets and liabilities of these
joint operations. In addition, where Tullow acts as operator to the joint operation, the gross liabilities and receivables (including
amounts due to or from non-operating partners) of the joint operation are included in the Group\u2019s balance sheet.
(f) Business combinations
The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or
other assets are acquired. The consideration transferred for the acquisition comprises of:
- Fair values of the assets transferred;
- Liabilities incurred to the former owners of the acquired business;
- Equity interests issued by the group;
- Fair value of any asset or liability resulting from a contingent consideration arrangement; and
- Fair value of any pre-existing equity interest in the subsidiary.
The Group determines that it has acquired a business when the acquired set of activities and assets include an input and a substantive
process that together signi\ufb01cantly contribute to the ability to create outputs. The acquired process is considered substantive if it is
critical to the ability to continue producing outputs, and the inputs acquired include an organised workforce with the necessary skills,
knowledge, or experience to perform that process or it signi\ufb01cantly contributes to the ability to continue producing outputs and is
considered unique or scarce or cannot be replaced without signi\ufb01cant cost, effort, or delay in the ability to continue producing outputs.
Identi\ufb01able assets acquired and liabilities and contingent liabilities assumed when control is obtained over a business, and when an
interest or an additional interest is acquired in a joint operation which is a business are, with limited exceptions, measured initially at
their fair values at the acquisition date.
Acquisition-related costs are expensed as incurred.
The excess of the consideration transferred, amount of any non-controlling interest in the acquired entity, and acquisition-date fair
value of any previous equity interest in the acquired entity over the fair value of the net identi\ufb01able assets acquired is recorded as
goodwill. If those amounts are less than the fair value of the net identi\ufb01able assets of the business acquired, the difference is
recognised directly in pro\ufb01t or loss as a bargain purchase.
(g) Revenue from contracts with customers
Revenue from contracts with customers represents the sales value, net of VAT, of the Group\u2019s share of liftings in the year.
Revenue is recognised when control of the goods or services are transferred to the customer at an amount that re\ufb02ects the
consideration to which the Group expects to be entitled in exchange for those goods or services. The Group has concluded that it
is the principal in all of its revenue arrangements since it controls the goods or services before transferring them to the customer.
The crude oil produced by the upstream operations is sold to external customers. Revenue from the sale of crude oil is recognised
at the point in time when control of the product is transferred to the customer, which is typically when goods are delivered, and title
has passed. The transportation and shipping costs associated with the transfer of the product to the point of sale is recognised as a
selling cost.
Under the terms of the relevant production sharing arrangements, the Group is entitled to its participating share in the crude oil based
on the Group\u2019s working interest. Revenue from contracts with customers is recognised based on the actual volumes sold to
customers. No adjustments are made to revenue for any differences between volumes sold to customers and unsold volumes which
the Group is entitled to sell based on its working interest. Revenue in respect of such volumes is only recognised when there is a
transfer of output to the Group\u2019s customers. Differences between the volume which the Group is entitled to sell based on its working
interest and the actual volumes that the Group has sold to customers are recognised as an under/overlift (note (g)) within cost of sales.
Under the terms of the Production Sharing Contracts in Gabon and C\u00f4te d\u2019Ivoire, the Group is not required to pay any corporate income
taxes. The share of the pro\ufb01t oil which the government is entitled to is deemed to include a portion representing the notional
corporate income tax paid by the government on behalf of the contractors. This portion of notional corporate income tax is presented
as an income tax expenses with a corresponding amount recognised in Revenue.
The Group\u2019s sales of crude oil are priced based on the consideration speci\ufb01ed in contracts with customers with reference to quoted
market prices in active markets, adjusted for a quality differential based on gravity of the crude oil sold relative to Brent. Invoices are
typically paid on 30-60 day terms.
For certain non-operated arrangements, the Group\u2019s stake is structured as a carried interest, in which all costs relating to the
performance of petroleum operations are borne by the operator and other joint venture partners and are recovered upon production.
The recognition of revenue is on net basis, where the Group only accounts for its share of pro\ufb01t oil.
(h) Over/underlift
Lifting or offtake arrangements for oil and gas produced in certain of the Group\u2019s jointly owned operations are such that each
participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between
cumulative entitlement and cumulative production less stock is underlift or overlift. Underlift and overlift are valued at market value
and included within receivables and payables respectively. Movements during an accounting period are adjusted through cost of sales
such that gross pro\ufb01t is recognised on an entitlements basis.
(i) Inventories
Inventories, other than oil products, are stated at the lower of cost and net realisable value. Cost is determined on a weighted average
cost basis and comprises direct purchase costs. Net realisable value is determined by reference to prices existing at the balance
sheet date, less estimated costs of completion and the estimated costs necessary to make the sale.
Oil product is stated at net realisable value and changes in net realisable value are recognised in the income statement.
(j) Foreign currencies
The US dollar is the presentational currency of the Group. For the purpose of presenting consolidated \ufb01nancial statements, the assets
and liabilities of the Group\u2019s non-US dollar-denominated entities are translated at exchange rates prevailing on the balance sheet
date. Income and expense items are translated at the average exchange rate for the period. Currency translation adjustments arising
on the restatement of opening net assets of non-US dollar subsidiaries, together with differences between the subsidiaries\u2019 results
translated at average rates versus closing rates, are recognised in the statement of comprehensive income and expense and
transferred to the foreign currency translation reserve. All resulting exchange differences are classi\ufb01ed as equity until disposal of the
subsidiary. On disposal, the cumulative amounts of the exchange differences are recognised as income or expense.
Transactions in foreign currencies are recorded at the rates of exchange ruling at the transaction dates. Monetary assets and
liabilities are translated into functional currency at the exchange rate ruling at the balance sheet date, with a corresponding charge
or credit to the income statement. However, exchange gains and losses arising on monetary items receivable from or payable to a
foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign
operation, are recognised in the foreign currency translation reserve and recognised in pro\ufb01t or loss on disposal of the net investment.
In addition, exchange gains and losses arising on long-term foreign currency borrowings which are a hedge against the Group\u2019s
overseas investments are dealt with in reserves.
Accounting policies continued
Year ended 31 December 2022
(k) Intangible, exploration and evaluation assets and oil and gas assets
The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Pre-licence costs are expensed in
the period in which they are incurred. All licence acquisition, exploration and evaluation costs and directly attributable administration
costs are initially capitalised in cost centres by well, \ufb01eld or exploration area, as appropriate.
These costs are then written off as exploration costs in the income statement unless commercial reserves have been established or
the determination process has not been completed and there are no indications of impairment.
Exploration and evaluation assets are tested for impairment when reclassi\ufb01ed to development assets, or whenever facts and
circumstances indicate impairment. An impairment loss is recognised for the amounts by which the exploration and evaluation
assets\u2019 carrying amount exceeds their recoverable amount. The recoverable amount is the higher of the exploration and evaluation
asset\u2019s fair value less cost to sell and their value in use.
Once commercial reserves are found, exploration and evaluation assets are tested for impairment and transferred to development
assets. No depreciation and/or amortisation is charged during the exploration and evaluation phase.
All \ufb01eld development costs are capitalised as property, plant and equipment. Property, plant and equipment related to production
activities is amortised in accordance with the Group\u2019s depletion and amortisation accounting policy.
Cash consideration received on farm-down of exploration and evaluation assets is credited against the carrying value of the asset.
The excess amount over the carrying value of the asset is recognised as a gain on disposal of exploration and evaluation assets in the
statement of pro\ufb01t or loss.
(l) Commercial reserves
Commercial reserves are proven and probable oil and gas reserves, which are de\ufb01ned as the estimated quantities of crude oil, natural
gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a speci\ufb01ed degree of certainty to
be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50%
statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and probable
reserves and a 50% statistical probability that it will be less.
(m) Depletion and amortisation
All expenditure carried within each \ufb01eld is amortised from the commencement of production on a unit of production basis, which is
the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the
production in the period, generally on a \ufb01eld-by-\ufb01eld basis or by a group of \ufb01elds which are reliant on common infrastructure. Costs
used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future \ufb01eld development
costs required to recover the commercial reserves remaining. Changes in the estimates of commercial reserves or future \ufb01eld
development costs are dealt with prospectively.
(n) Impairment of property, plant and equipment
The Group assesses at each reporting date whether there is an indication that an asset (or CGU) may be impaired. In assessing
whether an impairment is required, the carrying value of the asset or CGU is compared with its recoverable amount. The recoverable amount
is the higher of the asset\u2019s/CGU\u2019s fair value less costs of disposal (FVLCD) and value in use (VIU). Given the nature of the Group\u2019s
activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers or similar
transactions are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment
charges described below is VIU. The Group estimates VIU using a discounted cash \ufb02ow model.
In order to discount the future cash \ufb02ows the Group calculates asset or CGU-speci\ufb01c discount rates.
The discount rates are based on an assessment of a relevant peer group\u2019s post-tax weighted average cost of capital (WACC).
The post-tax WACC is subsequently grossed up to a pre-tax rate. The Group then deducts any exploration risk premium which is
implicit within a peer group\u2019s WACC and subsequently applies additional country risk premium for all CGUs, an element of which
is determined by whether the assets are onshore or offshore.
Where there is evidence of economic interdependency between \ufb01elds, such as common infrastructure, the \ufb01elds are grouped
as a single CGU for impairment purposes.
Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit
to the income statement, net of any amortisation that would have been charged since the impairment.
(o) Decommissioning
Provision for decommissioning is recognised in full when the related facilities are installed. A corresponding amount equivalent to the
provision is also recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated
cost of decommissioning, discounted to its net present value using a risk-free rate, and is re-assessed each year in accordance with
local conditions and requirements. Changes in the estimated timing of decommissioning or decommissioning cost estimates are
dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and
equipment. The unwinding of the discount on the decommissioning provision is included as a \ufb01nance cost.
(p) Property, plant and equipment \u2013 non-oil and gas assets
Property, plant and equipment is stated in the balance sheet at cost less accumulated depreciation and any recognised impairment loss.
Depreciation on property, plant and equipment other than production assets is provided at rates calculated to write off the cost less
the estimated residual value of each asset on a straight-line basis over its expected useful economic life of between three and ten years.
(q) Borrowing costs
Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that
necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such
time as the assets are substantially ready for their intended use or sale.
All other \ufb01nance costs, which include interest on borrowings calculated using the effective interest method as described in paragraph
(aa), obligations under \ufb01nance leases, the unwinding effect of discounting provisions and exchange differences, are recognised in the
income statement in the period in which they are incurred.
(r) Share issue expenses and share premium account
Costs of share issues are written off against the premium arising on the issues of share capital.
(s) Taxation
Current and deferred tax, including UK corporation tax and overseas corporation tax, are provided at amounts expected to be paid using
the tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred corporation tax is
recognised on all temporary differences that have originated but not reversed at the balance sheet date where transactions or events
that result in an obligation to pay more, or right to pay less, tax in the future have occurred at the balance sheet date. Deferred tax
assets are recognised only to the extent that it is considered more likely than not that there will be suitable taxable pro\ufb01ts from which
the underlying temporary differences can be deducted. Deferred tax is measured on a non-discounted basis.
Deferred tax is provided on temporary differences arising on acquisitions that are categorised as business combinations. Deferred tax
is recognised at acquisition as part of the assessment of the fair value of assets and liabilities acquired. Any deferred tax is charged or
credited in the income statement as the underlying temporary difference is reversed.
Petroleum revenue tax (PRT) is treated as an income tax and deferred PRT is accounted for under the temporary difference method.
UK PRT refunds are included in the income statement and is taxable for UK corporation tax.
(t) Pensions
Contributions to the Group\u2019s de\ufb01ned contribution pension schemes are charged to operating pro\ufb01t on an accrual basis.
(u) Derivative \ufb01nancial instruments
The Group uses derivative \ufb01nancial instruments, such as forward currency contracts and commodity options contracts, to hedge
its foreign currency risks and commodity price risks respectively.
Derivatives are recognised initially at fair value at the date a derivative contract is entered into and are subsequently remeasured
to their fair value at each reporting date. The resulting gain or loss is recognised in pro\ufb01t or loss immediately unless the derivative is
designated and effective as a hedging instrument, in which event the timing of the recognition in pro\ufb01t or loss depends on the nature
of the hedge relationship.
For the purpose of hedge accounting, hedges are classi\ufb01ed as:
- fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability or an unrecognised
\ufb01rm commitment;
- cash \ufb02ow hedges when hedging the exposure to variability in cash \ufb02ows that is either attributable to a particular risk;
- associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an
unrecognised \ufb01rm commitment; and
- hedges of a net investment in a foreign operation.
At the inception of a hedge relationship, the Group formally designates and documents the hedge relationship to which it wishes
to apply hedge accounting.
Accounting policies continued
Year ended 31 December 2022
(u) Derivative \ufb01nancial instruments continued
The documentation includes identi\ufb01cation of the hedging instrument, the hedged item, the nature of the risk being hedged and how
the Group will assess whether the hedging relationship meets the hedge effectiveness requirements (including the analysis of sources
of hedge ineffectiveness and how the hedge ratio is determined). A hedging relationship quali\ufb01es for hedge accounting if it meets all
of the following effectiveness requirements:
- There is \u2018an economic relationship\u2019 between the hedged item and the hedging instrument;
- The effect of credit risk does not \u2018dominate the value changes\u2019 that result from that economic relationship; and
- The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually
hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item.
If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management
objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship
(i.e. rebalances the hedge) so that it meets the qualifying criteria again.
The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The
changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in
the time value hedge reserve. If the hedged item is transaction related, the time value is reclassi\ufb01ed to pro\ufb01t or loss when the hedged
item affects pro\ufb01t or loss. If the hedged item is time-period related, then the amount accumulated in the time value hedge reserve is
reclassi\ufb01ed to pro\ufb01t or loss on a rational basis. Those reclassi\ufb01ed amounts are recognised in pro\ufb01t or loss in the same line as the
hedged item. Furthermore, if the Group expects that some or all of the loss accumulated in hedging reserve will not be recovered in
the future, that amount is immediately reclassi\ufb01ed to pro\ufb01t or loss.
Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable,
which is the rate that exactly discounts estimated future cash receipts through the expected life of the \ufb01nancial asset to that asset\u2019s
net carrying amount.
Cash \ufb02ow hedges
The effective portion of the gain or loss on the hedging instrument is recognised in OCI in the cash \ufb02ow hedge reserve, while any
ineffective portion is recognised immediately in the statement of pro\ufb01t or loss. The cash \ufb02ow hedge reserve is adjusted to the lower
of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item.
The Group uses oil option contracts for its exposure to volatility of Dated Brent prices. The ineffective portion relating to option
contracts is recognised as gain or loss on hedging instruments in the Group income statement.
Amounts previously recognised in other comprehensive income and accumulated in equity are reclassi\ufb01ed to pro\ufb01t or loss in the
periods when the hedged item affects pro\ufb01t or loss, in the same line as the recognised hedged item.
Cash \ufb02ow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying
criteria. This includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable
to occur, or when the hedging instrument is sold, terminated or exercised without replacement or rollover. When cash \ufb02ow hedge
accounting is discontinued, amounts previously recognised within other comprehensive income remain in equity until the forecast
transaction occurs and are reclassi\ufb01ed to pro\ufb01t or loss or transferred to the initial carrying amount of a non-\ufb01nancial asset or liability
as above. If the forecast transaction is no longer expected to occur, amounts previously recognised within other comprehensive
income will be immediately reclassi\ufb01ed to pro\ufb01t or loss.
(v) Convertible bonds
Where bonds issued with certain conversion rights are identi\ufb01ed as compound instruments, the liability and equity components are
separately recognised. The fair value of the liability component on initial recognition is calculated by discounting the contractual stream
of future cash \ufb02ows using the prevailing market interest rate for similar non-convertible debt. The difference between the fair value of
the liability component and the fair value of the whole instrument is recorded as equity.
Transaction costs are apportioned between the liability and the equity components of the instrument based on the amounts initially
recognised. The liability component is subsequently measured at amortised cost using the effective interest rate method, in line with
our other \ufb01nancial liabilities. The equity component is not remeasured. On conversion of the instrument, equity is issued and the
liability component is derecognised. The original equity component recognised at inception remains in equity. No gain or loss is
recognised on conversion. In an event of a repayment of the liability component, the original equity component is transferred to
retained earnings.
(w) Leases
On inception of a contract, the Group assesses whether the contract is, or contains, a lease. The contract is, or contains, a lease if it
conveys the right to control the use of an identi\ufb01ed asset for a period of time in exchange for consideration. To determine whether
the contract conveys the right to control the use of an identi\ufb01ed asset, the Group assesses whether the contract involves the use of an
identi\ufb01ed asset, the Group has the right to obtain substantially all of the economic bene\ufb01ts from the use of the asset throughout the
period of use, and the Group has the right to direct the use of the asset.
i) Lessee accounting
Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use
by the Group. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability, in case of
Joint operation, adjusted for any amount receivable from Joint Venture Partners and any lease payments made at or before the
commencement date, plus any initial direct costs incurred and an estimate of costs required to remove or restore the underlying
asset, less any lease incentives received. The right-of-use asset is depreciated over the shorter of the asset\u2019s useful life and the lease
term on a straight-line basis, or applying the unit of production method, and the Joint Venture receivable is allocated against the
monthly Joint Venture billing cycle.
The initial measurement of the corresponding lease liability is at the present value of the lease payments that are not paid at the lease
commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Group\u2019s
incremental borrowing rate.
The lease payments include \ufb01xed payments, less any lease incentive receivable, variable leases payments based on an index or rate,
and amounts expected to be payable by the lessee under residual value guarantees.
The lease liability is subsequently measured at amortised cost using the effective interest method. It is remeasured when there is a
change in future lease payments arising from a change in an index or rate, if there is a change in the Group\u2019s estimate of the amount
expected to be payable under a residual value guarantee or if the Group changes its assessment of whether it will exercise a purchase,
extension or termination option.
When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset
or is recorded in pro\ufb01t or loss if the carrying amount of the right-of-use asset has been reduced to zero.
The Group has elected not to recognise right-of-use assets and lease liabilities for short-term leases that have a lease term of
12 months or less, and leases of low-value assets with a value of $5,000.
Over the course of a lease contract, there will be taxable timing differences that could give rise to deferred tax, subject to local tax
laws and regulations.
Extension and termination options are included in a number of property and equipment leases across the Group. These are used
to maximise operational \ufb02exibility in terms of managing the assets used in the Group\u2019s operations. The majority of extension and
termination options held are exercisable only by the Group and not by the respective lessor.
(x) Share-based payments
The Group has applied the requirements of IFRS 2 Share-based Payments. The Group has share-based awards that are equity settled
and cash settled as de\ufb01ned by IFRS 2. The fair value of the equity settled awards has been determined at the date of grant of the
award allowing for the effect of any market-based performance conditions. This fair value, adjusted by the Group\u2019s estimate of the
number of awards that will eventually vest as a result of non-market conditions, is expensed uniformly over the vesting period.
The fair values were calculated using a binomial option pricing model with suitable modi\ufb01cations to allow for employee turnover after
vesting and early exercise. Where necessary, this model is supplemented with a Monte Carlo model. The inputs to the models include:
the share price at date of grant; exercise price; expected volatility; expected dividends; risk-free rate of interest; and patterns of
exercise of the plan participants.
For cash settled awards, a liability is recognised for the goods or service acquired, measured initially at the fair value of the liability.
At each balance sheet date until the liability is settled, and at the date of settlement, the fair value of the liability is remeasured, with
any changes in fair value recognised in the income statement.
Accounting policies continued
Year ended 31 December 2022
(y) Financial assets
At initial recognition, the Group measures a \ufb01nancial asset at its fair value plus, in the case of a \ufb01nancial asset not at fair value through
pro\ufb01t or loss (FVPL), transaction costs that are directly attributable to the acquisition of the \ufb01nancial asset. Transaction costs of
\ufb01nancial assets carried at FVPL are expensed in pro\ufb01t or loss. The subsequent measurement of \ufb01nancial assets depends on their
classi\ufb01cation, as set out overleaf.
i) Financial assets measured at amortised cost
Assets are subsequently classi\ufb01ed and measured at amortised cost when the business model of the Company is to collect contractual
cash \ufb02ows and the contractual terms give rise to cash \ufb02ows that are solely payments of principal and interest. These assets are carried at
amortised cost using the effective interest method if the time value of money is signi\ufb01cant. Gains and losses are recognised in pro\ufb01t
or loss when the assets are derecognised, modi\ufb01ed or impaired. This category of \ufb01nancial assets includes trade and other receivables.
Financial assets measured at amortised cost include trade receivables, loans and other receivables that have \ufb01xed or determinable
payments that are not quoted in an active market. Loans and receivables are measured at amortised cost using the effective interest
method, less any impairment. Interest income is recognised by applying the effective interest rate, except for short-term receivables
when the recognition of interest would be immaterial.
ii) Financial asset measured at fair value through other comprehensive income
Assets are subsequently classi\ufb01ed and measured at fair value through other comprehensive income when the business model of the
Company is to collect contractual cash \ufb02ows and sell the \ufb01nancial assets, and the contractual cash \ufb02ows represent solely payments
of principal and interest.
iii) Financial assets measured at fair value through pro\ufb01t or loss
Financial assets are classi\ufb01ed as measured at fair value through pro\ufb01t or loss when the asset does not meet the criteria to be
measured at amortised cost or fair value through other comprehensive income. These assets are carried on the balance sheet at
fair value with gains or losses recognised in the income statement. Derivatives, other than those designated as effective hedging
instruments, are included in this category.
As at 31 December 2022, the Group does not have any \ufb01nancial assets classi\ufb01ed at fair value through pro\ufb01t or loss or other
comprehensive income.
Regular way purchases and sales of \ufb01nancial assets are recognised on trade date, being the date on which the Group commits to
purchase or sell the asset. Financial assets are derecognised when the rights to receive cash \ufb02ows from the \ufb01nancial assets have
expired or have been transferred and the Group has transferred substantially all the risks and rewards of ownership.
Impairment of trade and joint venture receivables
The Group applies the IFRS 9 simpli\ufb01ed approach to measuring expected credit losses which uses a lifetime expected loss allowance
for all trade receivables. To measure the expected credit losses, trade receivables have been grouped based on shared credit risk
characteristics and days past due.
The expected loss rates are based on the payment pro\ufb01les of sales over the historical period and the corresponding historical credit
losses experienced within this period. These rates are then applied to the gross carrying amount of the receivable to arrive at the loss
allowance for the period. Based on Management assessment the credit loss in trade receivables and joint venture receivable as at
31 December 2022 would be immaterial; therefore, in line with IFRS 9, no impairment was recognised (2021: $nil).
In order to minimise the risk of default, credit risk is managed on a Group basis (note 18).
(z) Cash and cash equivalents
Cash and cash equivalents comprise cash at bank, demand deposits and other short-term highly liquid investments that are readily
convertible to a known amount of cash and are subject to an insigni\ufb01cant risk of changes in value.
(aa) Effective interest method
The effective interest method is a method of calculating the amortised cost of a \ufb01nancial asset and of allocating interest income over
the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees on
points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts)
through the expected life of the \ufb01nancial asset, or, where appropriate, a shorter period.
Income is recognised on an effective interest basis for debt instruments other than those \ufb01nancial assets classi\ufb01ed as at FVTPL.
(ab) Financial liabilities
The measurement of \ufb01nancial liabilities is determined by the initial classi\ufb01cation.
i) Financial liabilities at fair value through pro\ufb01t or loss:
Those balances that meet the de\ufb01nition of being held for trading are measured at fair value through pro\ufb01t or loss. Such liabilities are
carried on the balance sheet at fair value with gains or losses recognised in the income statement.
ii) Financial liabilities measured at amortised cost:
All \ufb01nancial liabilities not meeting the criteria of being classi\ufb01ed at fair value through pro\ufb01t or loss are classi\ufb01ed as \ufb01nancial liabilities
measured at amortised cost. The instruments are initially recognised at its fair value net of transaction costs that are directly
attributable to the issue of \ufb01nancial liability. Subsequent to initial recognition, \ufb01nancial liabilities are measured at amortised cost
using the effective interest method.
Trade payables and borrowings fall under this category of \ufb01nancial instruments.
As at 31 December 2022 all \ufb01nancial liabilities are measured at amortised cost.
The Group derecognises a \ufb01nancial liability when it is extinguished, i.e. when the obligation speci\ufb01ed in the contract is discharged
or cancelled or expires. A substantial modi\ufb01cation of the terms of an existing \ufb01nancial liability or a part of it is accounted for as an
extinguishment of the original \ufb01nancial liability and the recognition of a new \ufb01nancial liability.
Offsetting of \ufb01nancial instruments:
Financial assets and \ufb01nancial liabilities are offset and the net amount is reported in the consolidated statement of \ufb01nancial position
if there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis, to
realise the assets and settle the liabilities simultaneously.
(ac) Equity instruments
Equity instruments are classi\ufb01ed according to the substance of the contractual arrangements entered into.
An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities.
Equity instruments issued by the Group are recorded at the proceeds received, net of direct issue costs.
(ad) Insurance proceeds
Insurance proceeds related to lost production under the Business Interruption insurance policy are recorded as other operating
income in the income statement. Proceeds related to compensation for incremental operating costs under the Business Interruption and
Hull and Machinery insurance policies are recorded within the operating costs line of cost of sales. Proceeds related to compensation
for capital costs under insurance policies are recorded within pro\ufb01t and loss with corresponding cost for replacement asset as additions to
property, plant and equipment. Insurance proceeds are recognised at the point when the realisation of income is virtually certain.
(ae) Provisions
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that
an out\ufb02ow of resources embodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of
the amount of the obligation.
Onerous contracts
If the Group has a contract that is onerous, the present obligation under the contract is recognised and measured as a provision.
However, before a separate provision for an onerous contract is established, the Group recognises any impairment loss that has
occurred on assets dedicated to that contract.
An onerous contract is a contract under which the unavoidable costs (i.e., the costs that the Group cannot avoid because it has the
contract) of meeting the obligations under the contract exceed the economic bene\ufb01ts expected to be received under it. The unavoidable
costs under a contract re\ufb02ect the least net cost of exiting from the contract, which is the lower of the cost of ful\ufb01lling it and any
compensation or penalties arising from failure to ful\ufb01l it. The cost of ful\ufb01lling a contract comprises the costs that relate directly to
the contract (i.e., both incremental costs and an allocation of costs directly related to contract activities).
Accounting policies continued
Year ended 31 December 2022
(af) Critical accounting judgements
The Group assesses critical accounting judgements annually. The following are the critical judgements, apart from those involving
estimations which are dealt with in policy (ag), that the Directors have made in the process of applying the Group\u2019s accounting policies
and that have the most signi\ufb01cant effect on the amounts recognised in the Financial Statements.
Carrying value of intangible exploration and evaluation assets (note 9)
The amounts for intangible exploration and evaluation assets represent active exploration projects. These amounts will be written
off to the income statement as exploration costs unless commercial reserves are established or the determination process is not
completed and there are no indications of impairment in accordance with the Group\u2019s accounting policy. The process of determining
whether there is an indicator for impairment or calculating the impairment requires critical judgement.
The key areas in which Management has applied judgement and estimation are as follows: the Group\u2019s intention to proceed with a
future work programme for a prospect or licence; the likelihood of licence renewal or extension; the assessment of whether sufficient
data exist to indicate that, although a development in the speci\ufb01c area is likely to proceed, the carrying amount of the exploration and
evaluation asset is unlikely to be recovered in full from successful development or by sale; and the success of a well result or
geological or geophysical survey.
Details on impact of these key estimates using sensitivities applied to impairment models can be found in note 9.
The most material area where judgement was applied during 2022 was in the assessment of the value in use (VIU) of the Kenyan CGU
and assessing the likelihood of recovery of the net book value of the asset. A trigger for potential impairment reversal was identi\ufb01ed
following the Group\u2019s increase in long-term oil price assumption resulting in an increase in the underlying value of the project. Due to
the stage of this project being pre-\ufb01nal investment decision (FID) and only having 2C resources booked, the VIU assessment required
estimation and judgement in a number of different aspects including oil prices differentials, uncontracted cost pro\ufb01les and certain
\ufb01scal terms. Furthermore, the Group has identi\ufb01ed the following estimation uncertainties, which require judgement, in respect to the
Group\u2019s ability to realise the estimated VIU; receiving an acceptable offer from a strategic partner, obtaining \ufb01nancing for the project
and government deliverables. These items require satisfactory resolution before the Group can take FID. Due to the binary nature of
these uncertainties the Group was unable to either adjust the cash \ufb02ows or discount rate appropriately. It has therefore used its
judgement and assessed the probability of achieving FID and therefore the recognition of commercial reserves.
This probability was applied to the VIU to determine a risk adjusted VIU and compared against the net book value of the asset.
Based on this there is no impairment or impairment reversal as at 31 December 2022. Should the uncertainties around the project
be resolved there will be a reversal of previously recognised impairment. However, if the uncertainties are not resolved there will
be an impairment of $253 million.
Lease accounting (note 19)
Discount rate
The Group has assessed the appropriate incremental borrowing rate applicable for each contract. Management has applied the
practical expedient which allows for the adoption of a portfolio approach, where a single discount rate for a portfolio of leases with
similar characteristics can be applied. As the Group has external borrowings with a consortium of lenders, these are considered
the best reference for the incremental borrowing rate for the Group. The weighted average cost of those borrowings is considered
to the Group's 'all in rate', at the lease commencement date if the interest rate implicit in the lease is not readily determinable. As at
31 December 2022, the Group's incremental borrowing rate was 9.82%.
Determination of the lease term
Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. Extension and
termination options are included in a number of property and equipment leases across the Group. These are used to maximise
operational \ufb02exibility in terms of managing the assets used in the Group\u2019s operations. For leases relating to Joint Venture operations
where there is an option to extend, the Group will only proceed after it has received Joint Venture approval to extend. At the inception
of new leases in relation to joint arrangements they do not include any period covered by an extension option in the lease term
because they cannot be reasonably certain that approval from the other venturers can be obtained. The majority of extension and
termination options held are exercisable only by the Group and not by the respective lessor.
Fair valuation of additional interest acquired in Ghana assets (note 15)
The additional interest acquired in the Ghana assets has been recorded at fair value as required under IFRS 3. The property, plant and
equipment acquired through the business combination has been recognised at the fair value based on the net present value of the
discounted future cash \ufb02ows. Signi\ufb01cant inputs to the valuation include short- and long-term commodity prices, reserve estimates,
production volume pro\ufb01les, planned development expenditure, cost pro\ufb01les and discount rates, and are consistent with those applied
by the management when testing assets for impairments.
(ag) Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a
signi\ufb01cant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next \ufb01nancial year, are
discussed below.
Carrying value of property, plant and equipment (note 10)
Management performs impairment reviews on the Group\u2019s property, plant and equipment assets at least annually with reference to
indicators in IAS 36 Impairment of Assets. Where indicators of impairments or impairment reversals are present and an impairment
or impairment reversal test is required, the calculation of the recoverable amount requires estimation of future cash \ufb02ows within
complex impairment models.
Key assumptions and estimates in the impairment models relate to: commodity prices assumptions, pre-tax discount rates, commercial
reserves and the related cost pro\ufb01les. Proven and probable reserves are estimates of the amount of oil and gas that can be economically
extracted from the Group\u2019s oil and gas assets. The Group estimates its reserves using standard recognised evaluation techniques.
The estimate is reviewed at least annually by Management and by independent consultants. Proven and probable reserves are
determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the
total amount of remaining recoverable reserves and the proportion of the gross reserves which are attributable to host governments
under the terms of the Production Sharing Contracts. Future development costs are estimated taking into account the level of
development required to produce the reserves by reference to operators, where applicable, and internal engineers.
Net entitlement reserves estimates are subsequently calculated using the current oil price and cost recovery assumptions, in line with
the relevant agreements. Changes in reserves as a result of factors such as production cost, recovery rates, grade of reserves or oil
and gas prices could impact the depletion rates, carrying value of assets (refer to the Commercial Reserves and Contingent Resources
Summary on page 176).
The estimation applied by Management to the exploration risk premium adjustment to its impairment discount rates, estimated future
commodity prices and forecast cash \ufb02ows on the TEN asset would have the most material impact on the 2022 Financial Statements
should Management have concluded differently.
Details on the impact of these key estimates and judgements using sensitivity applied to impairment models can be found in note 10.
Uncertain tax treatments
The Group is subject to various material claims which arise in the ordinary course of its business in various jurisdictions, including cost
recovery claims, claims from regulatory bodies and both corporate income tax and indirect tax claims. The Group is in formal dispute
proceedings regarding a number of these tax claims. The resolution of tax positions, through negotiation with the relevant tax authorities
or litigation, can take several years to complete. In assessing whether these claims should be provided for in the Financial Statements,
Management has considered them in the context of the applicable laws and relevant contracts for the countries concerned. Management
has applied judgement in assessing the likely outcome of the claims and has estimated the \ufb01nancial impact based on external tax and
legal advice and prior experience of such claims.
Due to the uncertainty of such tax items, it is possible that on conclusion of an open tax matter at a future date the outcome may differ
signi\ufb01cantly from Management\u2019s estimate. If the Group was unsuccessful in defending itself from all of these claims, the result would
be additional liabilities of $1,024.0 million (2021: $1,025.5 million) which includes $32.4 million of interest and penalties (2021: $33.6 million).
Provisions of $106.4 million (2021: $127.9 million) are included in income tax payable ($70.6 million (2021: $34.1 million)), deferred tax
liability ($nil (2021:41.0 million)), and provisions ($35.8 million (2021: $52.8 million)). Where these matters relate to expenditure which is
capitalised within Intangible Exploration and Evaluation Assets and Property, Plant and Equipment, any difference between the amounts
accrued and the amounts settled is capitalised within the relevant asset balance, subject to applicable impairment indicators. Where
these matters relate to producing activities or historical issues, any differences between the accrued and settled amounts are taken to
the group income statement.
The provisions and contingent liabilities relating to these disputes have decreased following the conclusion of tax authority challenges
and matters lapsing under the statute of limitations, but have increased, following new claims being initiated and extrapolation of
exposures through to 31 December 2022, giving rise to an overall decrease in provision of $21.5 million and decrease in contingent liability
of $1.5 million.
(ag) Key sources of estimation uncertainty continued
Ghana tax assessments
In October 2021, Tullow Ghana Limited (TGL) \ufb01led a Request for Arbitration with the International Chamber of Commerce (\u201cICC\u201d)
disputing the $320 million branch pro\ufb01ts remittance tax (BPRT) assessment issued as part of the direct tax audit for the \ufb01nancial
years 2014 to 2016. The Ghana Revenue Authority (GRA) is seeking to apply BPRT under a law which the Group considers is not
applicable to TGL, since it falls outside the tax regime provided for in the Petroleum Agreements and relevant double tax treaties.
The parties have agreed a procedural timetable for the arbitration under which the \ufb01rst Tribunal hearing will be held in October 2023.
In December 2022, TGL received a $190.5 million corporate income tax assessment and payment demand from the GRA relating to the
disallowance of loan interest for the \ufb01nancial years 2010 to 2020. The Group has previously disclosed assessments by the GRA relating
to the same issue; this revised assessment supersedes all previous claims. The Group considers the assessment to breach TGL\u2019s
rights under its Petroleum Agreements. In February 2023, TGL \ufb01led a Request for Arbitration with the ICC, disputing the assessment
with the suspension of TGL\u2019s obligation to pay any amount in relation to the assessment until the dispute is formally resolved.
In December 2022, TGL received a $196.5 million corporate income tax assessment and payment demand from the GRA relating to
proceeds received by Tullow during the \ufb01nancial years 2016 to 2019 under Tullow\u2019s corporate Business Interruption Insurance policy.
The Group considers the assessment to breach TGL\u2019s rights under its Petroleum Agreements. In February 2023, TGL \ufb01led a Request for
Arbitration to the ICC, disputing the assessment with the suspension of TGL\u2019s obligation to pay any amount in relation to the
assessment until the dispute is formally resolved.
The Group continues to engage with the Government of Ghana with the aim of resolving all tax disputes on a mutually acceptable basis.
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow $118 million of tax relief in respect of development costs incurred by Tullow
Bangladesh Limited (TBL). The NBR subsequently issued a payment demand to TBL in February 2020 for Taka 3,094 million (c.$37 million)
requesting payment by 15 March 2020. However, under the Production Sharing Contract (PSC), the Government is required to
indemnify TBL against all taxes levied by any public authority, and the share of production paid to Petrobangla (PB), Bangladesh\u2019s
national oil company, is deemed to include all taxes due which PB is then obliged to pay to the NBR. TBL sent the payment demand
to PB and the Government requesting the payment or discharge of the payment demand under their respective PSC indemnities.
On 14 June 2021, TBL issued a formal notice of dispute under the PSC to the Government and PB. A further request for payment was
received from NBR on 28 October 2021 demanding settlement by 15 November 2021. Arbitration proceedings were initiated under
the PSC on 29 December 2021. A procedural hearing was held on 28 June 2022 which set the timetable for the process going forward.
The \ufb01rst submissions have been made in October 2022 with the \ufb01rst Tribunal hearing scheduled for May 2024.
Other items
Other items totalling $280.0 million (2021: 547.5 million) comprise exposures in respect of claims for corporation tax in respect of
disallowed expenditure or withholding taxes that are either currently under discussion with the tax authorities or which arise in
respect of known issues for periods not yet under audit.
Timing of cash \ufb02ows
While it is not possible to estimate the timing of tax cash \ufb02ows in relation to possible outcomes with certainty, Management
anticipates that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments.
Notes to the Group Financial Statements
Year ended 31 December 2022
Note 1. Segmental reporting
The information reported to the Group\u2019s Chief Executive Officer for the purposes of resource allocation and assessment of segment
performance is focused on four Business Units \u2013 Ghana, Non-operated producing assets including Uganda and decommissioning assets,
Kenya and Exploration. Therefore, the Group\u2019s reportable segments under IFRS 8 are Ghana, Non-operated, Kenya and Exploration.
The following tables present revenue, loss and certain asset and liability information regarding the Group\u2019s reportable business
segments for the years ended 31 December 2022 and 31 December 2021.
Ghana
$m
Non-Operated
$m
Kenya
$m
Exploration
$m
Corporate
$m
Total
$m
2022
Sales revenue by origin 1,578.5 524.0 \u2013 \u2013 (319.4) 1,783.1
Segment result1 692.5 337.3 (0.5) (102.6) (337.5) 589.2
Other provisions\u00b2 (4.1)
Gain on bargain purchase 196.8
Other gains and losses 3.1
Unallocated corporate expenses\u00b3 (51.1)
Operating pro\ufb01t 733.9
Gain on hedging instruments 0.8
Finance income 42.9
Finance costs (335.5)
Pro\ufb01t before tax 442.1
Income tax expense (393.0)
Pro\ufb01t after tax 49.1
Total assets 3,827.7 380.6 265.6 46.0 519.7 5,039.6
Total liabilities\u2074 (2,220.5) (401.6) (14.1) (4.6) (2,858.3) (5,499.1)
Other segment information
Capital expenditure:
Property, plant and equipment 342.9 26.9 \u2013 \u2013 0.9 370.7
Intangible exploration and evaluation assets 0.9 (1.7) (2.1) 42.1 \u2013 39.2
Depletion, depreciation and amortisation (362.1) (52.7) (1.3) \u2013 (9.7) (425.8)
Impairment of property, plant and equipment, net (380.6) (10.6) \u2013 \u2013 \u2013 (391.2)
Exploration costs written off (0.9) 1.8 (0.5) (105.6) \u2013 (105.2)
1. Segment result is a non-IFRS measure which includes gross pro\ufb01t, exploration costs written off and impairment of property, plant and equipment. See reconciliation below.
2. This is included within the Restructuring costs and other provisions in the Group Income Statement.
3. Unallocated expenditure include amounts of a corporate nature and not speci\ufb01cally attributable to a geographic area.
4. Total liabilities \u2013 Corporate comprise of the Group\u2019s external debt and other non-attributable liabilities.
Reconciliation of segment result
2022
$m
2021
Restated
1
$m
Segment result 589.2 532.3
Add back:
Exploration costs written off 105.2 59.9
Impairment of property, plant and equipment 391.2 54.3
Gross pro\ufb01t 1,085.6 646.5
1. Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year ended
31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. Refer to note 6.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 1. Segmental reporting continued
All sales are made to external customers. Included in revenue arising from Ghana and Non-Operated segments are revenues of
approximately $696.9 million, $566.1 million, $310.9 million and $242.3 million relating to the Group\u2019s customers who each contribute more
than 10% of total sales revenue (2021: 329.6 million, $256.9 million, $151.1 million and $145.2 million). As the sales of oil and gas are made on
global markets and are highly liquid, the Group does not place reliance on the largest customers mentioned above. Payment terms are
typically 30 days from the bill of lading.
Ghana
$m
Non-Operated
$m
Kenya
$m
Exploration
$m
Corporate
$m
Total
$m
2021
Sales revenue by origin \u2013 restated
6
1,020.4 417.9 \u2013 \u2013 (152.9) 1,285.4
Segment result1- restated
6
469.8 298.7 \u2013 (70.5) (165.7) 532.3
Other provisions\u00b2 6.6 \u2013 (13.2) \u2013 (52.1) (58.7)
Gain on disposal 120.3
Unallocated corporate expenses\u00b3 (67.2)
Operating pro\ufb01t 526.7
Finance income 44.3
Finance costs (356.1)
Pro\ufb01t before tax 214.9
Income tax expense - restated
6
(295.6)
Loss after tax (80.7)
Total assets \u2013 restated
6
4,283.8 501.2 264.6 122.3 368.8 5,540.6
Total liabilities\u2074 \u2013 restated
6
(2,529.3) (478.9) (18.0) (12.8) (2,967.7) (6,006.7)
Other segment information
Capital expenditure:
Property, plant and equipment 99.6 43.9 \u2013 \u2013 4.6 148.1
Intangible exploration and evaluation assets\u2075 1.2 (11.8) 8.2 48.8 \u2013 46.3
Depletion, depreciation and amortisation (334.5) (28.8) (1.4) (0.1) (14.1) (378.9)
Impairment of property, plant and equipment, net (119.1) 64.8 \u2013 \u2013 \u2013 (54.3)
Exploration costs written off\u2075 (1.2) 11.8 \u2013 (70.5) \u2013 (59.9)
1. Segment result is a non-IFRS measure which includes gross pro\ufb01t, exploration costs written off and impairment of property, plant and equipment. See reconciliation below.
2. This is included within the Restructuring costs and other provisions in the Group Income Statement.
3. Unallocated expenditure include amounts of a corporate nature and not speci\ufb01cally attributable to a geographic area.
4. Total liabilities \u2013 Corporate comprise of the Group\u2019s external debt and other non-attributable liabilities.
5. Non-operated segment includes release of $15.3 million indirect tax provision following settlement.
6. Segment revenue and segment result allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classi\ufb01cation
of loss on realisation of the cash \ufb02ow hedges within reportable segments. Total balances have remained unchanged.
The allocation for the year ended 31 December 2021 increased revenue for Ghana and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the hedging
loss of $152.9 million was allocated to Corporate.
Total assets and total liabilities allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classi\ufb01cation of tax
assets and liabilities within reportable segments. The above balances have been restated by:
Ghana
$m
Non-Operated
$m
Kenya
$m
Exploration
$m
Corporate
$m
Total
$m
Total assets \u2013 increase/(decrease) (35.1) 5.4 (6.0) (22.0) 57.8 \u2013
Total liabilities \u2013 (increase)/decrease (32.0) (11.2) 6.0 24.0 13.2 \u2013
In addition, revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year
ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. Refer to note 6.
Note 1. Segmental reporting continued
Sales revenue and non-current assets by origin
Sales
revenue
2022
$m
Sales
revenue
2021
Restated
2
$m
Non-current
assets
3
2022
$m
Non-current
assets
3
2021
$m
Ghana 1,578.5 1,020.4 3,087.4 3,131.3
Total Ghana 1,578.5 1,020.4 3,087.4 3,131.3
Kenya \u2013 \u2013 258.5 261.7
Total Kenya \u2013 \u2013 258.5 261.7
Argentina \u2013 \u2013 33.6 30.4
C\u00f4te d\u2019Ivoire \u2013 \u2013 2.4 \u2013
Guyana \u2013 \u2013 \u2013 69.1
Total Exploration \u2013 \u2013 36.0 99.5
Gabon 477.0 312.6 132.6 148.7
C\u00f4te d\u2019Ivoire 47.0 46.2 59.2 81.4
Equatorial Guinea
1
\u2013 59.1 \u2013 \u2013
Total Non-Operated 524.0 417.9 191.8 230.1
Corporate (319.4) (152.9) 23.4 35.6
Total 1,783.1 1,285.4 3,597.1 3,758.3
1. The disposal of Equatorial Guinea was completed in March 2021 (refer to note 8).
2. Segment revenue allocation between the reportable segments has been restated to correct a prior period error arising from incorrect classi\ufb01cation of loss on realisation
of the cash \ufb02ow hedges within reportable segments. Total balances have remained unchanged. The allocation for the year ended 31 December 2021 increased revenue
for Ghana and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the hedging loss of $152.9 million was allocated to Corporate.
In addition, Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. For the year ended 31 December 2022, this resulted in
an increase to revenue in C\u00f4te d\u2019Ivoire of $3.2 million and Gabon of $18.2 million (2021: $5.5 million and $6.7 million, respectively), and a corresponding increase to
income tax expense. Refer to note 6.
3. Non-current assets exclude derivative \ufb01nancial instruments and deferred tax assets.
Note 2. Total revenue
2022
$m
2021
Restated
1
$m
Revenue from contracts with customers
Revenue from crude oil sales
1
2,102.5 1,438.4
Total revenue from contracts with customers 2,102.5 1,438.4
Loss on realisation of cash \ufb02ow hedges (319.4) (153.0)
Total revenue 1,783.1 1,285.4
1. Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year ended
31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. Refer to note 6.
Finance income has been presented as part of net \ufb01nancing costs (refer to note 5).
Note 3. Staff costs
The average annual number of employees employed by the Group worldwide was:
2022
Number
2021
Number
Administration 182 192
Technical 194 186
Total 376 378
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 3. Staff costs continued
Staff costs in respect of those employees were as follows:
2022
$m
2021
$m
Salaries 66.3 64.3
Social security costs 7.0 10.4
Pension costs 5.3 5.2
Redundancy costs 0.1 3.1
Total staff costs 78.7 83.0
A proportion of the Group\u2019s staff costs shown above is recharged to the Group\u2019s Joint Venture Partners, a proportion is allocated
to operating costs and a proportion is capitalised into the cost of \ufb01xed assets under the Group\u2019s accounting policy for exploration,
evaluation and production assets with the remainder classi\ufb01ed as an administrative overhead cost in the income statement.
The net staff costs recognised in the income statement were $10.5 million (2021: $23.8 million).
The Group operates de\ufb01ned contribution pension schemes for staff and Executive Directors. The contributions are payable to external
funds which are administered by independent trustees. Contributions during the year amounted to $5.3 million (2021: $5.2 million).
Details of Directors\u2019 remuneration, Directors\u2019 transactions and Directors\u2019 interests are set out in the part of the Directors\u2019 Remuneration
Report described as having been audited, which forms part of these Financial Statements.
Note 4. Other costs
Notes
2022
$m
2021
$m
Operating pro\ufb01t is stated after charging/(deducting):
Operating costs 266.5 268.7
Depletion and amortisation of oil and gas and leased assets
1
10 410.7 360.9
Underlift, overlift and oil stock movements (46.3) (20.0)
Royalties 61.7 40.5
Share-based payment charge included in cost of sales 23 0.4 0.5
Other cost of sales 4.4 (11.7)
Total cost of sales 697.5 638.9
Share-based payment charge included in administrative expenses 23 5.4 11.1
Depreciation of other \ufb01xed assets
1
10 15.1 18.0
Other administrative costs 30.5 35.0
Total administrative expenses 51.0 64.1
Total restructuring costs and other provisions
2
4.2 61.8
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts 2.1 1.6
The audit of the Company\u2019s subsidiaries pursuant to legislation 0.6 0.8
Total audit services 2.7 2.4
Non-audit services:
Audit-related assurance services \u2013 half-year review 0.5 0.5
Corporate \ufb01nance services 1.0 0.4
Other services \u2013 0.1
Total non-audit services 1.5 1.0
Total 4.2 3.6
1. Depreciation expense on leased assets of $60.9 million as per note 10 includes a charge of $3.9 million on leased administrative assets, which is presented within
administrative expenses in the income statement. The remaining balance of $57.0 million relates to other leased assets and is included within cost of sales.
2. This includes restructuring and redundancy costs of $0.1 million (2021: $3.1 million) as well as movements in other provisions of $4.1 million (2021: $58.7 million).
Note 4. Other costs continued
Fees payable to Ernst & Young LLP and its associates for non-audit services to the Company are not required to be disclosed because
the consolidated Financial Statements are required to disclose such fees on a consolidated basis.
Corporate \ufb01nance services are in relation to Class 1 Disposal. Non-audit services were 55% of audit services during the year.
Details of the Company\u2019s policy on the use of the auditor for non-audit services, the reasons why the auditor was used rather than
another supplier and how the auditor\u2019s independence and objectivity are safeguarded are set out in the Audit Committee Report on
pages 63 to 68. No services were provided pursuant to contingent fee arrangements.
Note 5. Net \ufb01nancing costs
Notes
2022
$m
2021
$m
Interest on bank overdrafts and borrowings 250.4 243.0
Interest on obligations under leases 19 76.4 83.4
Total borrowing costs 326.8 326.4
Finance and arrangement fees 0.3 19.1
Other interest expense 2.4 3.0
Unwinding of discount on decommissioning provisions 20 6.0 7.6
Total \ufb01nance costs 335.5 356.1
Interest income on amounts due from Joint Venture Partners for leases 19 (29.6) (38.8)
Other \ufb01nance income (13.3) (5.5)
Total \ufb01nance income (42.9) (44.3)
Net \ufb01nancing costs 292.6 311.8
Note 6. Taxation on pro\ufb01t on continuing activities
Notes
2022
$m
2021
Restated
1
$m
Current tax on pro\ufb01ts for the year
UK corporation tax (11.8) (19.2)
Foreign tax 321.0 162.2
Taxes paid in kind under production sharing contracts 21.4 12.2
Adjustments in respect of prior periods (3.3) (3.3)
Total corporate tax 327.3 151.9
UK petroleum revenue tax (2.8) (1.2)
Total current tax 324.5 150.7
Deferred tax
Origination and reversal of temporary differences
UK corporation tax 11.4 18.1
Foreign tax 54.0 80.3
Adjustments in respect of prior periods (2.9) 43.8
Total deferred corporate tax 62.5 142.2
Deferred UK petroleum revenue tax 6.0 2.7
Total deferred tax 21 68.5 144.9
Total income tax expense 393.0 295.6
1. Income tax expense has been restated following a revision to the Group's accounting policy. The revenue from certain Production Sharing Contracts in Gabon and
C\u00f4te d\u2019Ivoire is now presented gross of corporate income taxes deemed to have been paid as part of the Government's share of pro\ufb01t oil. This has resulted in an increase
to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. This change has been
implemented to more accurately represent the income taxes suffered by the Group on its pro\ufb01ts in Gabon and C\u00f4te d\u2019Ivoire and to be more comparable with other
entities in the sector.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 6. Taxation on pro\ufb01t on continuing activities continued
The tax rate applied to pro\ufb01t on continuing activities in preparing the reconciliation below is the UK corporation tax rate applicable to
the Group\u2019s UK pro\ufb01ts. The difference between the total income tax expense shown above and the amount calculated by applying the
standard rate of UK corporation tax applicable to UK pro\ufb01ts of 19% (2021: 19%) to the pro\ufb01t before tax is as follows:
2022
$m
2021
Restated
$m
Pro\ufb01t from continuing activities before tax 442.1 214.9
Tax on pro\ufb01t from continuing activities at the standard UK corporation tax rate of 19% (2021: 19%) 84.0 40.8
Effects of:
Non-deductible exploration expenditure
a
0.5 8.5
Other non-deductible expenses 27.8 13.3
Deferred tax asset not recognised
b
138.5 94.4
Utilisation of tax losses not previously recognised (0.4) (0.1)
Adjustment relating to prior years
c
(6.2) 40.4
Other tax rates applicable outside the UK 214.6 118.3
Other income not subject to corporation tax (0.1) (20.0)
Tax impact of acquisition through business combination (note 15) (65.7) \u2013
Total income tax expense for the year 393.0 295.6
a. Includes recurring explorations costs written off where there is no deferred tax impact.
b. Includes hedging losses and interest expense.
c. Includes movements in provisions in respect of uncertain tax treatments.
The Finance Act 2021 sets the Corporation Tax main rate at 19% for the \ufb01nancial year beginning 1 April 2022 and at 25% for the \ufb01nancial
year beginning 1 April 2023. These changes were enacted on 10 June 2021 and hence the effect of the change on the deferred tax
balances has been included, depending upon when deferred tax is expected to reverse.
The Group\u2019s pro\ufb01t before taxation will continue to arise in jurisdictions where the effective rate of taxation differs from that in the
UK, such as Ghana (35%) and Gabon convention \ufb01elds (50%), Gabon PSC \ufb01elds (35%) and CDI PSC (25%). Furthermore, there is no tax
bene\ufb01t arising on net interest and hedging expense in the UK. Accordingly, the Group\u2019s tax charge will continue to vary according to
the jurisdictions in which pre-tax pro\ufb01ts arise.
The Group has tax losses of $4,237.4 million (2021: $5,400.0 million) that are available for offset against future taxable pro\ufb01ts in the
companies in which the losses arose. Deferred tax assets have not been recognised in respect of losses of $4,128.9 million
(2021: $4,749.7 million) as it is not sufficiently probable that there will be future taxable pro\ufb01ts against which these losses can be utilised.
The Group has recognised deferred tax assets of $35.8 million (2021: $222.0 million) in relation to tax losses only to the extent of
anticipated future taxable income or gains in relevant jurisdictions. The Group has suffered these losses in either the current or
preceding period in the tax jurisdiction to which the deferred tax asset relates. The tax losses can be carried forward inde\ufb01nitely.
There are no temporary differences relating to unremitted earnings of overseas subsidiaries as the Group is able to control the timing
of the reversal of these temporary differences and it is probable that they will not reverse in the foreseeable future.
Tax relating to components of other comprehensive income
During 2022 nil tax expense (2021: $2.8 million of tax credit) has been recognised through other comprehensive income.
Note 7. Earnings /(loss) per ordinary share
Basic earnings/(loss) per ordinary share amounts are calculated by dividing net pro\ufb01t/(loss) for the year attributable to ordinary equity
holders of the Parent by the weighted average number of ordinary shares outstanding during the year.
Diluted earnings per ordinary share amounts are calculated by dividing net pro\ufb01t/(loss) for the year attributable to ordinary equity
holders of the Parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average
number of dilutive ordinary shares that would be issued if employee and other share options were converted into ordinary shares.
2022
$m
2021
$m
Pro\ufb01t/ (loss) for the year
Net pro\ufb01t attributable to equity shareholders 49.1 (80.7)
Effect of dilutive potential ordinary shares \u2013 \u2013
Diluted net earnings/ (loss) attributable to equity shareholders 49.1 (80.7)
2022
Number
2021
Number
Number of shares
Basic weighted average number of shares 1,437,099,966 1,418,378,706
Dilutive potential ordinary shares 48,375,409 45,708,796
Diluted weighted average number of shares 1,485,475,375 1,464,087,502
Note 8. Asset disposals
On 31 March 2021, the Group completed the sale of its assets in Equatorial Guinea with a cash consideration received of $88.9 million.
This transaction included contingent future payments of up to $16.0 million which are linked to asset performance and oil price.
As per the SPA, a further $5.0 million of additional consideration was also received on completion of Dussafu Marin Permit in Gabon.
On 9 June 2021, the Group completed the asset sale of Dussafu Marin Permit in Gabon with a cash consideration received of $39.0 million.
This transaction included contingent future payments of up to $24.0 million which are linked to asset performance and oil price.
Given Tullow no longer holds interest in the above assets, based on publicly available information the Company has assessed that the
asset performance condition is not met. Accordingly, no contingent consideration has been recognised as of 31 December 2022.
Book value of assets disposed
Equatorial
Guinea
$m
Dussafu
$m
Total
$m
Property, plant and equipment 72.9 52.0 124.9
Inventories 6.9 3.2 10.1
Other current assets 68.5 1.7 70.2
Total assets disposed 148.3 56.9 205.2
Trade and other payables (36.1) (18.5) (54.6)
Provisions (118.2) (4.7) (122.9)
Current tax liabilities (13.6) \u2013 (13.6)
Deferred tax liabilities (17.8) \u2013 (17.8)
Total liabilities disposed (185.7) (23.2) (208.9)
Net (liabilities)/ assets disposed (37.4) 33.7 (3.7)
Cash consideration 93.8 39.0 132.8
Transaction costs (11.0) (0.3) (11.3)
Gain on disposal
1
120.2 5.0 125.2
1. In 2021, in addition to $125.2 million gain on disposals recognised following the Equatorial Guinea and Dussafu disposals, the Group recognised a loss of $5.1 million
relating to its sale of Dutch assets to Hague and London Oil plc (HALO) in 2017, and a gain of $0.2 million relating to other transactions during the period which resulted
in an overall gain of $120.3 million. No gain on disposals was recognised for the year ended 31 December 2022.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 8. Asset disposals continued
Uganda
Contingent asset
During 2020, the Group completed the disposal of its interest in Uganda for upfront cash consideration of $500.0 million, with
$75.0 million due on FID and contingent future payments linked to oil prices. Given the existing uncertainties around the project,
management has concluded that the conditions for recognition of an asset associated with contingent consideration under IFRS 15
were not met as of 31 December 2022.
Note 9. Intangible exploration and evaluation assets
2022
$m
2021
$m
At 1 January 354.6 368.2
Additions
1
39.2 46.3
Amounts written off (105.2) (59.9)
At 31 December 288.6 354.6
1. In Kenya, proceeds from Early Oil Pilot Scheme (EOPS) cargo sales of $6.9 million have been recorded as a credit against capital expenditure.
The below table provides a summary of the exploration costs written off on a pre tax basis by country.
Country CGU
Rationale for
2022
write-off
2022
write-off
$m
2022
Remaining
recoverable
amount
$m
Guyana Kanuku a, b 75.3 \u2013
Guyana Orinduik b 22.4 \u2013
C\u00f4te d\u2019Ivoire Block 524 c 3.1 \u2013
New Ventures Various d 3.0 \u2013
Other Various 1.4 \u2013
Total write-off 105.2 \u2013
a. Unsuccessful well costs written off.
b. Licence relinquishments, expiry, planned exit or reduced activity.
c. Current year expenditure on assets previously written off.
d. New Ventures expenditure is written off as incurred.
In Kenya, the Group had received a 15-month licence extension from September 2020 to December 2021 which was contingent on certain
conditions, including submission of a technically and commercially compliant Field Development Plan (FDP). On 10 December 2021,
Tullow and its Joint Venture Partners submitted an FDP to the Government of Kenya and ful\ufb01lled its licence obligations. The Group
expects a production licence to be granted once due Government process has been completed.
Since 1 January 2022, there have been ongoing discussions with the Government of Kenya on approval of the FDP and securing
government deliverables. An updated FDP was submitted on 3rd of March and is being reviewed by the Government of Kenya before
rati\ufb01cation by the Kenyan Parliament. In addition, the Company continues to progress with the farm down process.
In line with its accounting policy, the Group has performed a VIU assessment of the Kenya asset following identi\ufb01cation of triggers for
impairment and impairment reversal. This resulted in an NPV signi\ufb01cantly in excess of the book value of $252.6 million. However, the
Group has identi\ufb01ed the following estimation uncertainties in respect to the Group\u2019s ability to realise the estimated VIU; receiving and
subsequently \ufb01nalising an acceptable offer from a strategic partner and securing governmental approvals relating thereto, obtaining
\ufb01nancing for the project and government deliverables. These items require satisfactory resolution before the Group can take a Final
Investment Decision. Due to the binary nature of these uncertainties the Group was unable to either adjust the cash \ufb02ows or discount
rate appropriately. It has therefore used its judgement and assessed a probability of achieving FID and therefore the recognition of
commercial reserves. This probability was applied to the VIU to determine a risk adjusted VIU and compared against the net book
value of the asset. Based on this there is no impairment or impairment reversal as at 31 December 2022. The cash \ufb02ows in the VIU
assessment were discounted using a pre- tax nominal r discount rate of 20%. Refer to note 10 for oil price assumptions.
Note 9. Intangible exploration and evaluation assets continued
Should the uncertainties around the project be resolved, there will be a reversal of a previously recorded impairment. However, if
the uncertainties are not resolved there will be an additional impairment of $252.6 million. A reduction or increase in the two-year
forward curve of $5/bbl, based on the approximate range of annualised average oil price over recent history, and a reduction or
increase in the medium and long-term price assumptions of $5/bbl, based on the range of annualised average historical prices, are
considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices speci\ufb01ed above would
result in an impairment charge of $31.6 million, whilst increases to oil prices speci\ufb01ed above would result in an impairment reversal of
$35.2 million. A 1% change in the pre-tax discount rate would result in an impairment charge of $34.2 million. The Group believes a 1%
change in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group\u2019s and a peer group of
companies\u2019 impairments. Refer to Note 26 for Net Zero Emission scenarios.
Country CGU
Rationale for
2021
write-off
2021
write-off
$m
2021
Remaining
recoverable
amount
$m
Suriname Blocks 47 and 62 b,d 58.9 \u2013
Uganda Exploration areas 1,1A, 2 and 3A c (15.3) \u2013
Gabon Tchatamba d 2.2 \u2013
Peru Licences Z67 and Z68 b 1.8 \u2013
C\u00f4te d\u2019Ivoire Block 520 b 6.6 \u2013
Other Various a 5.7 \u2013
Total write-off 59.9 \u2013
a. Current year expenditure on assets previously written off.
b. Licence relinquishments, expiry, planned exit or reduced activity.
c. Release of indirect tax provision following settlement.
d. Unsuccessful well costs written off.
Note 10. Property, plant and equipment
Notes
2022
Oil and gas
assets
$m
2022
Other \ufb01xed
assets
$m
2022
Right of use
assets
$m
2022
Total
$m
2021
Oil and gas
assets
$m
2021
Other \ufb01xed
assets
$m
2021
Right of use
assets
$m
2021
Total
$m
Cost
At 1 January 10,521.7 69.5 1,091.7 11,682.9 10,460.2 69.6 1,018.6 11,548.4
Additions 1 305.2 2.0 63.5 370.7 73.0 1.6 73.5 148.1
Acquisitions
1
15 473.2 \u2013 \u2013 473.2
Transfer
2
15 \u2013 \u2013 86.6 86.6
Asset retirement \u2013 (38.1) (41.7) (79.8) \u2013 (1.4) \u2013 (1.4)
Currency translation
adjustments (117.5) (3.4) (3.3) (124.2) (11.5) (0.3) (0.4) (12.2)
At 31 December 11,182.6 30.0 1,196.8 12,409.4 10,521.7 69.5 1,091.7 11,682.9
Depreciation, depletion,
amortisation and impairment
At 1 January (8,263.7) (53.8) (450.8) (8,768.3) (7,915.9) (42.3) (352.3) (8,310.5)
Charge for the year 4 (353.7) (11.2) (60.9) (425.8) (304.9) (13.4) (60.6) (378.9)
Impairment loss (391.2) \u2013 \u2013 (391.2) (54.3) \u2013 \u2013 (54.3)
Capitalised depreciation \u2013 \u2013 (46.1) (46.1) \u2013 \u2013 (38.0) (38.0)
Asset retirement \u2013 38.1 41.7 79.8 \u2013 1.4 \u2013 1.4
Currency translation
adjustments 120.2 2.5 0.9 123.6 11.4 0.5 0.1 12.0
At 31 December (8,888.4) (24.4) (515.2) (9,428.0) (8,263.7) (53.8) (450.8) (8,768.3)
Net book value at 31 December 2,294.2 5.6 681.6 2,981.4 2,258.0 15.7 640.9 2,914.6
1. This relates to an acquisition through business combination discussed in Note 15.
2. As a result of Ghana pre-emption a proportionate amount has been reclassi\ufb01ed from receivables due from joint venture partners to right of use assets relating to the
Group\u2019s existing interest in lease contracts in the joint operation.
The currency translation adjustments arose due to the movement against the Group\u2019s presentational currency, USD, of the Group\u2019s UK
assets, which have a functional currency of GBP.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 10. Property, plant and equipment continued
During 2022 and 2021 the Group applied the following nominal oil price assumptions for impairment assessments:
Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 onwards
2022 $84/bbl $79/bbl $70/bbl $70/bbl $70/bbl $70/bbl in\ufb02ated at 2%
2021 $76/bbl $71/bbl $68/bbl $65/bbl $65/bbl $65/bbl in\ufb02ated at 2%
Trigger for
2022
impairment/
(reversal)
2022
Impairment/
(reversal)
$m
Pre-tax
discount rate
assumption
2022
Remaining
recoverable
amount
d
$m
Limande and Turnix CGU (Gabon) a (1.6) 15% 44.6
Tchatamba (Gabon) a (1.3) 15% 38.0
Oba and Middle Oba CGU (Gabon) a (0.4) 17% 11.8
Echira, Niungo and Igongo (Gabon) a (1.4) 17% 8.6
TEN (Ghana) b 380.6 13% 931.7
Mauritania a 12.8 n/a \u2013
UK CGU a,c 2.5 n/a \u2013
Impairment 391.2
a. Change to decommissioning estimate.
b. Revision of value based on revisions to reserves
c. The \ufb01elds in the UK are grouped into one CGU as all \ufb01elds within those countries share critical gas infrastructure.
d. The remaining recoverable amount of the asset is its value in use.
Impairments identi\ufb01ed in the TEN \ufb01elds of $380.6 million were primarily due to lower 2P reserves partially offset by oil price assumptions.
Oil prices stated above are benchmark prices to which an individual \ufb01eld price differential is applied. All impairment assessments are
prepared on a VIU basis using discounted future cash \ufb02ows based on 2P reserves pro\ufb01les. A reduction or increase in the two-year
forward curve of $5/bbl, based on the approximate range of annualised average oil price over recent history, and a reduction or
increase in the medium and long-term price assumptions of $5/bbl, based on the range of annualised average historical prices, are
considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices speci\ufb01ed above would
increase the impairment charge by $131.4 million for Ghana and increase the impairment by $19.2 million for Non-Operated, whilst
increases to oil prices speci\ufb01ed above would result in a credit to the impairment charge of $122.0 million for Ghana and no change to
Non-Operated. A 1% change in the pre-tax discount rate would increase the impairment by $33.0 million for Ghana and increase the
impairment by $2.9 million for Non-Operated. The Group believes a 1% change in the pre-tax discount rate to be a reasonable
possibility based on historical analysis of the Group\u2019s and peer group of companies\u2019 impairments.
For Net Zero Emissions sensitivities refer to Note 26.
Trigger for
2021
impairment/
(reversal)
2021
Impairment/
(reversal)
$m
Pre tax
discount rate
assumption
2021
Remaining
recoverable
amount
$m
Limande and Turnix CGU (Gabon) a,c (40.8) 13% 50.8
Ezanga (Gabon) a,c (17.0) 15% 22.4
Oba and Middle Oba CGU (Gabon) a,c (3.2) 15% 10.5
Espoir (C\u00f4te d\u2019Ivoire) a,c (8.7) 10% 81.4
TEN (Ghana) a,b,c 119.1 10% 1,171.4
Mauritania b 2.1 n/a \u2013
UK CGU b,d 2.8 n/a \u2013
Impairment 54.3
a. Increase to short, medium and long-term oil price assumptions.
b. Change to decommissioning estimate.
c. Revision of value based on revisions to reserves.
d. The \ufb01elds in the UK are grouped into one CGU as all \ufb01elds within those countries share critical gas infrastructure.
e. The remaining recoverable amount of the asset is its value in use.
Note 10. Property, plant and equipment continued
Impairments identi\ufb01ed in the TEN \ufb01elds of $119.1 million were primarily due to lower TEN 2P reserves and higher capital expenditure
partially offset by price and lower decommissioning costs. This is offset by impairment reversals mainly in Gabon of $61.1 million and
Espoir of $8.7 million as a result of higher oil prices and higher 2P reserves.
Oil prices stated above are benchmark prices to which an individual \ufb01eld price differential is applied. All impairment assessments are
prepared on a VIU basis using discounted future cash \ufb02ows based on 2P reserves pro\ufb01les. A reduction or increase in the two-year
forward curve of $5/bbl, based on the approximate range of annualised average oil price over recent history, and a reduction or increase
in the medium and long-term price assumptions of $5/bbl, based on the range of annualised average historical prices, are considered
to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices speci\ufb01ed above would increase the
impairment charge by $157.7 million for Ghana and reduce the impairment reversal by $12.4 million for Non-Operated, whilst increases
to oil prices speci\ufb01ed above would result in a credit to the impairment charge of $157.7 million for Ghana and increase the impairment
reversal by $1.3 million for Non-Operated. A 1% increase in the pre-tax discount rate would increase the impairment by $40.7 million
for Ghana and reduce the impairment reversal by $3.3 million for Non-Operated. The Group believes a 1% change in the pre-tax
discount rate to be a reasonable possibility based on historical analysis of the Group\u2019s and peer group of companies\u2019 impairment.
Note 11. Other assets
Notes
2022
$m
2021
$m
Non-current
Amounts due from Joint Venture Partners 19 323.3 486.0
VAT recoverable 3.8 3.1
327.1 489.1
Current
Amounts due from Joint Venture Partners 19 452.3 554.7
Underlifts 76.2 26.7
Prepayments 31.3 49.6
Other current assets 8.1 73.5
567.9 704.5
895.0 1,193.6
The decrease in non-current receivables from JV Partners compared to December 2021 mainly relates to reduction in time remaining
on the TEN FPSO lease, net decrease in GNPC (Ghana National Petroleum Corporation) receivable and reduction in partner share
following Ghana pre-emption.
The movement in current receivables from JV Partners relates mainly to timing of partner balances and reduction in partner share
following Ghana pre-emption.
The decrease in other current assets compared to 2021 is mainly due to a collection of the deferred consideration relating to the
Uganda disposal in March 2022 ($67.9 million net ).
Note 12. Inventories
2022
$m
2021
$m
Warehouse stock and materials 69.1 55.5
Oil stock 112.5 79.3
181.6 134.8
The increase in oil stock is associated with the timing of liftings of the Group's share of crude oil around period end.
Note 13. Trade receivables
Trade receivables comprise amounts due for the sale of oil. They are generally due for settlement within 30\u201360 days and are therefore
all classi\ufb01ed as current. The Group holds the trade receivables with the objective of collecting the contractual cash \ufb02ows and
therefore measures them subsequently at amortised cost using the effective interest method.
The balance of trade receivables as at 31 December 2022 of $26.8 million (2021:$99.8 million) mainly relates to oil sales in Gabon for
liftings between September and December 2022. The December Jubilee (Ghana) sale was settled before 31 December 2022.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 14. Cash and cash equivalents
Notes
2022
$m
2021
$m
Cash at bank 305.3 226.1
Short-term deposits and other cash equivalents 331.0 243.0
636.3 469.1
Cash and cash equivalents includes an amount of $74.7 million (2021: $92.4 million) which the Group holds as operator in Joint Venture
bank accounts. Included within cash at bank is $7.0 million (2021: $0.8 million) held in restricted bank accounts. This mainly consists
of $4.5 million held as security for performance bonds relating to work commitments on exploration licences.
Note 15. Business combination
On 17 March 2022 the Group completed the pre-emption related to the sale of Occidental Petroleum\u2019s (\u201cOxy\u201d) interests in the Jubilee
and TEN \ufb01elds in Ghana to Kosmos Energy. As a result of this acquisition, the Group\u2019s interest in the TEN \ufb01elds increased from 47.18%
to 54.84%, and from 35.48% to 39.0% in the Jubilee \ufb01eld. Tullow did not obtain control as a result of this transaction, as all joint venture
partners retain joint control.
The total purchase consideration, which was funded from cash on the balance sheet, comprises of $118.2 million cash settled on
completion, and $8.6 million subsequent post-completion adjustment paid in May 2022. There is no element of contingent
consideration included in the purchase price.
The fair values of the identi\ufb01able assets and liabilities acquired were:
Fair value
recognised on
acquisition
$m
Property, plant and equipment 473.2
Inventories 12.1
Other current assets 31.4
Total assets acquired 516.7
Trade and other payables (10.5)
Provisions (61.6)
Deferred tax liabilities (143.6)
Total liabilities assumed (215.5)
Net identi\ufb01able assets acquired 301.0
Purchase consideration transferred (126.8)
Deemed settlement of provision 22.6
Gain on bargain purchase 196.8
There were no acquisitions in the year ended 31 December 2021.
The property, plant and equipment acquired through the business combination has been recognised at the fair value based on the net
present value of the discounted future cash \ufb02ows. Signi\ufb01cant inputs to the valuation include short- and long-term commodity prices,
reserve estimates, production volume pro\ufb01les, planned development expenditure, cost pro\ufb01les and discount rates, and are consistent
with those applied by the management when testing assets for impairments.
The fair value of acquired other receivables is nil. The gross contractual amount for other receivables due is $0.9 million, with a loss
allowance of $0.9 million recognised on acquisition.
The deferred tax liability mainly comprises the tax effect of the accelerated depreciation for tax purposes of tangible assets.
Contingent liabilities recognised in a business combination
A contingent liability recognised in a business combination is initially measured at its fair value. Subsequently, it is measured at the
higher of the amount that would be recognised in accordance with the requirements for provisions as per IAS 37 \u201cProvisions,
Contingent Liabilities and Contingent Assets\u201d, or the amount initially recognised less (when appropriate) cumulative amortisation
recognised in accordance with the requirements for revenue recognition.
Note 15. Business combination continued
As part of the pre-emption Tullow has taken on pro-rated exposure relating to Anadarko WCTP Company\u2019s (\u201cAnadarko\u201d) BPRT and AOE
disputed claims. In February 2018, Anadarko, whom Oxy acquired the interests from, received a provisional assessment for AOE for
US$346.6 million, including a penalty of $329.5 million, (the portion of this claim related to Tullow\u2019s acquired interests was $67.2
million) covering \ufb01nancial years 2006 \u2013 2016 and in November 2018 the Ministry of Finance con\ufb01rmed that the assessment was
suspended pending the Government reaching a \ufb01nal view on the basis for calculating AOE. Anadarko continued to dispute the AOE
assessment issued and considered no AOE was payable for these periods. In September 2021, Anadarko received a revised tax audit
report from the Ghana Revenue Authority (GRA) for the \ufb01nancial years 2014 to 2018 including a $228.3 million branch pro\ufb01ts remittance
tax (BPRT) assessment (including late payment interest of $52.1 million) (the portion of this claim related to Tullow\u2019s acquired interests
was $67.1 million). The Anadarko BPRT assessment is covered by a Notice of Dispute issued in June 2020.
A contingent liability at fair value of $36.8 million was recognised at the acquisition date for provisions resulting from certain
contractual indemnities. There was no change in provision as at 31 December 2022.
Revenue and net pro\ufb01t contribution
The acquired business contributed revenues of $133.2 million and net pro\ufb01t of $19.6 million to the Group for the period from 17 March 2022
to 31 December 2022. If the acquisition had occurred on 1 January 2022, the consolidated pro-forma revenues would have been
$169.2 million higher and the consolidated pro-forma pro\ufb01t for the period ended 31 December 2022 would have been higher by $11.4 million.
These amounts have been calculated using the acquired interest\u2019s results and adjusting them for the additional depreciation and
amortisation that would have been charged assuming the fair value adjustments to property, plant and equipment had applied from
1 January 2022, together with the consequential tax effects.
Acquisition-related costs
Acquisition-related costs of $0.6 million are included in administrative expenses in the statement of pro\ufb01t or loss and in operating
cash \ufb02ows in the statement of cash \ufb02ows.
Recognition of gain on bargain purchase
The difference between the fair value of net assets acquired and consideration paid was recognised within the income statement
as gain on bargain purchase of $196.8 million. This is mostly due to the change in the oil markets from 2021, when the transaction
between Occidental Petroleum and Kosmos Energy was negotiated to March 2022, when the acquisition was completed by Tullow.
The consideration paid by Tullow for the acquired interest was based on the proportionate consideration agreed between Occidental
Petroleum and Kosmos Energy, subject to completion adjustments. Additionally, the original transaction between the two parties was
driven by the seller\u2019s intention to leave the region and dispose of the non-core elements of the portfolio which it had acquired from
Anadarko Petroleum in August 2019.
Note 16. Trade and other payables
Current liabilities
Notes
2022
$m
2021
$m
Trade payables 68.4 60.2
Other payables 51.4 57.4
Overlifts \u2013 0.7
Accruals\u00b9 379.3 381.3
Current portion of lease liabilities 19 251.2 251.5
750.2 751.1
1. Accruals mainly relate to capital expenditure, interest expense on bonds and staff-related expenses.
Non-current liabilities
Notes
2022
$m
2021
$m
Other non-current liabilities\u00b9 47.1 75.2
Non-current portion of lease liabilities 19 732.9 911.9
780.0 987.1
1. Other non-current liabilities include balances related to JV Partners.
Trade and other payables are non-interest bearing except for leases (note 19).
Payables related to operated Joint Ventures (primarily in Ghana and Kenya) are recorded gross with the amount representing the
partners\u2019 share recognised in amounts due from Joint Venture Partners (note 11). The change in trade payables and in other payables
predominantly represents timing differences and levels of work activity.
The decrease in non-current portion of lease liabilities mainly relates to reduction in time remaining on the TEN FPSO lease.
Note 17. Borrowings
2022
$m
2021
$m
Current
Borrowings \u2013 within one year
10.25% Senior Secured Notes due 2026 100.0 100.0
100.0 100.0
2022
$m
2021
$m
Non-current
Borrowings \u2013 after one year but within \ufb01ve years
7.00% Senior Notes due 2025 792.8 792.1
10.25% Senior Secured Notes due 2026 1,580.0 1,676.6
2,372.8 2,468.7
Carrying value of total borrowings 2,472.8 2,568.7
The Group\u2019s capital structure includes $1.7bn Senior Secured Notes (2026 Notes), $800 million Senior notes due 2025 (2025 Notes) and
a $500 million Super Senior Revolving Credit Facility (SSRCF) which will primarily be used for working capital purposes.
The 2026 Notes, maturing in May 2026, require an annual prepayment of $100 million, in May, of the outstanding principal amount plus
accrued and unpaid interest, with the balance due on maturity.
On 16 May 2022, the Group made the annual prepayment of $100 million of the 2026 Notes, which reduced total debt to $2.5 billion.
The 2025 Notes are due in a single payment in March 2025.
The SSRCF, maturing in December 2024, comprises of (i) a $500 million revolving credit facility and (ii) a $100 million letter of
credit facility. The revolving credit facility remains undrawn as at 31 December 2022. Letters of credit amounting to $44 million
(2021: $20 million) have been issued under the facility.
Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes and the SSRCF are $20.0 million, $7.0 million and $4.8 million respectively.
The 2026 Notes and the SSRCF are senior secured obligations of Tullow Oil Plc and are guaranteed by certain of the subsidiaries
of the Group.
Capital management
The Group de\ufb01nes capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders
and bene\ufb01ts to stakeholders and to safeguard the Group\u2019s ability to continue as a going concern. Tullow is not subject to any externally
imposed capital requirements. To maintain or adjust the capital structure, the Group may put in place new debt facilities, issue new
shares for cash, repay debt, engage in active portfolio management, adjust the dividend payment to shareholders, or undertake other
such restructuring activities as appropriate. The Group monitors capital on the basis of the gearing, being net debt divided by adjusted
EBITDAX, and maintains a policy target of less than 1x.
SSRCF covenants
The SSRCF does not have any \ufb01nancial maintenance covenants. Availability under the $500 million cash tranche of the facility is
determined on an annual basis with reference to the Net Present Value of the 2P reserves of the Group (2P NPV) at the end of the
preceding calendar year. SSRCF debt capacity is calculated as 2P NPV divided by 1.1x less senior secured debt outstanding.
Note 17. Borrowings continued
2025 Notes and 2026 Notes covenants
The 2025 Notes and the 2026 Notes are subject to customary high yield covenants including limitations on debt incurrence, asset
sales and restricted payments such as prepayments of junior debt and dividends.
Key covenants in the current business cycle are considered to be those related to debt incurrence and restricted payments.
For de\ufb01nitions of the capitalised terms used in the following paragraphs please refer to the offering memorandum of the 2025 Notes
and/or the 2026 Notes.
Tullow is permitted to incur additional debt if the ratio of Consolidated Cash Flow to Fixed Charges for the previous 12 months is at
least 2.25 times on a pro forma basis.
Tullow is permitted to incur secured debt if the 2P Reserves Coverage Ratio is at least 2.0 times on a pro forma basis.
Subject to certain conditions, Tullow is permitted to incur debt to re\ufb01nance the 2025 Notes on a like for like basis, i.e. subordinated to
the 2026 Notes.
Tullow would be permitted to make payments towards the 2025 Notes amounting to the greater of $100 million per year and 50% of the
Consolidated Net Income of the Company for the period from 1 January 2021 to the end of the most recently completed \ufb01scal half-year
for which internal \ufb01nancial statements are available if, after giving pro forma effect to the payment(s) if the 2P Reserves Coverage
Ratio is equal to or greater than 1.5 times.
Tullow would be permitted to make payments towards the 2025 Notes amounting to the greater of $100 million per year, 50% of the
Consolidated Net Income of the Company for the period from 1 January 2021 to the end of the most recently completed \ufb01scal half-year
for which internal \ufb01nancial statements are available and 100% of Consolidated Cash Flow per year if the 2P Reserves Coverage Ratio is
equal to or greater than 2.0 times and the Consolidated Leverage Ratio is less than 1.5 times.
The Company or its affiliates may, at any time and from time to time, seek to retire or purchase outstanding debt through cash
purchases and/or exchanges, in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or
exchanges, if any, will be upon such terms and at such prices as management may determine, and will depend on prevailing market
conditions, liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Note 18. Financial instruments
Financial risk management objectives
The Group\u2019s Corporate Treasury function provides services to the business, coordinates access to international \ufb01nancial markets,
monitors and manages the \ufb01nancial risks relating to the operations of the Group through internal management reports which analyse
exposures by degree and magnitude of risks. These risks include market risk (including currency risk, interest rate risk and price risk),
credit risk and liquidity risk.
The Group seeks to minimise the effects of these risks by using derivative \ufb01nancial instruments to hedge these risk exposures, if deemed
appropriate. The use of \ufb01nancial derivatives is governed by the Group\u2019s policies approved by the Board of Directors. Compliance with
policies and exposure limits are monitored and reviewed internally on a regular basis. The Group does not enter into or trade \ufb01nancial
instruments, including derivatives, for speculative purposes.
2022
$m
2021
$m
Financial assets
Financial assets at amortised cost
Trade receivables 26.8 99.8
Amounts due from Joint Venture Partners 775.6 1,040.7
Cash and cash equivalents 636.3 469.1
1,438.7 1,609.6
Financial liabilities
Liabilities at amortised cost
Trade payables 115.4 135.2
Other payables 430.7 439.4
Borrowings 2,472.8 2,568.7
Lease liabilities 984.1 1,163.4
Derivative \ufb01nancial instruments
Used for hedging 244.2 179.9
4,247.3 4,486.6
Note 18. Financial instruments continued
Fair values of \ufb01nancial assets and liabilities
With the exception of the 2026 Notes and the 2025 Notes, the Group considers the carrying value of all its \ufb01nancial assets and
liabilities to be materially the same as their fair value. The fair value of the 2026 Notes and 2025 Notes as determined using market
value at 31 December 2022, was $1,364.8 million (2021: $1,814.2 million) and $490.0 million (2021: $661.0 million) respectively. These are
compared to their carrying value of $1,680.0 million (2021: $1,776.7 million) and $792.9 million (2021: $792.1 million). The 2026 Notes and
the 2025 Notes are categorised as level 1 in the fair value hierarchy.
The Group has no material \ufb01nancial assets that are past due. No material \ufb01nancial assets are impaired at the balance sheet date.
All \ufb01nancial assets and liabilities with the exception of derivatives are measured at amortised cost.
Fair values of derivative instruments
All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income
statement, unless the derivatives have been designated as a cash \ufb02ow hedge. Fair value is the amount for which the asset or liability
could be exchanged in an arm\u2019s-length transaction at the relevant date. Where available, fair values are determined using quoted
prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based
transactions, or using standard valuation techniques for the applicable instruments and commodities involved.
The Group\u2019s derivative carrying and fair values were as follows:
Assets/liabilities
2022
Less than
1 year
$m
2022
1\u20133
years
$m
2022
Total
$m
2021
Less than
1 year
$m
2021
1\u20133
years
$m
2021
Total
$m
Cash \ufb02ow hedges
Oil derivatives (162.1) (49.7) (211.8) (56.7) (66.5) (123.2)
(162.1) (49.7) (211.8) (56.7) (66.5) (123.2)
Deferred premium
Oil derivatives (24.2) (8.2) (32.4) (24.3) (32.4) (56.7)
(24.3) (32.4) (56.7)
Total assets \u2013 \u2013 \u2013 \u2013 \u2013 \u2013
Total liabilities (186.3) (57.9) (244.2) (81.0) (98.9) (179.9)
Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide.
The following provides an analysis of the Group\u2019s \ufb01nancial instruments measured at fair value, grouped into Levels 1 to 3 based on the
degree to which the fair value is observable:
Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities;
Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable
for the asset or liability, either directly or indirectly; and
Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are
not based on observable market data.
All the Group\u2019s derivatives are Level 2 (2021: Level 2). There were no transfers between fair value levels during the year.
For \ufb01nancial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between
levels by re-assessing categorisation (based on the lowest-level input which is signi\ufb01cant to the fair value measurement as a whole)
at the end of each reporting period.
Note 18. Financial instruments continued
Offsetting of \ufb01nancial instruments
Financial assets and liabilities are offset and the net amount is reported in the Group balance sheet when there is a legally enforceable
right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability
simultaneously. No material enforceable master netting agreements were identi\ufb01ed.
The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts
recognised for \ufb01nancial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset
in the Group balance sheet.
31 December 2022
Gross
amounts
recognised
$m
Gross
amounts
offset
in Group
balance
sheet
$m
Net amounts
presented
in Group
balance
sheet
$m
Derivative assets \u2013 \u2013 \u2013
Derivative liabilities (244.2) \u2013 (244.2)
31 December 2021
Gross
amounts
recognised
$m
Gross
amounts
offset
in Group
balance
sheet
$m
Net amounts
presented
in Group
balance
sheet
$m
Derivative assets 0.2 (0.2) \u2013
Derivative liabilities (180.1) 0.2 (179.9)
Commodity price risk
The Group uses a number of derivatives to mitigate the commodity price risk associated with its underlying oil revenue. Such
commodity derivatives tend to be priced using benchmarks, such as Dated Brent, which correlate as far as possible to the underlying
oil revenue. There is an economic relationship between the hedged items and the hedging instruments due to a common underlying,
i.e. Dated Brent, between them. Forecast oil sales, which are based on Dated Brent, are hedged with options which have Dated Brent
as reference price. An increase in Dated Brent will cause the value of the hedged item and hedging instrument to move in opposite
directions. The Group has established a hedge ratio of 1:1 for the hedging relationships as the underlying risk of the commodity
derivatives is identical to the hedged risk components. To test the hedge effectiveness, the Group uses the hypothetical derivative
method and compares the changes in the fair value of the hedging instruments against the changes in fair value of the hedged items
attributable to the hedged risks. The Group hedges its estimated oil revenues on a portfolio basis, aggregating its oil revenues from
substantially all of its African oil interests.
As at 31 December 2022 and 31 December 2021, all of the Group\u2019s oil derivatives have been designated as cash \ufb02ow hedges. The Group\u2019s
oil hedges have been assessed to be highly effective.
Financial risk management is adopted centrally for the Group. The Group adopts a risk component hedging strategy. This results from
designating the variability in all the cash \ufb02ows attributable to the change in the benchmark price per the oil sales contracts where the
critical terms of the hedged item and hedging instrument match.
The following table demonstrates the timing, volumes and average \ufb02oor price protected for the Group\u2019s commodity hedges:
Hedging position as at 31 December 2022 2023 2024
Oil volume (bopd) 33,095 11,305
Average \ufb02oor price protected ($/bbl) 55.0 55.0
Hedging position as at 31 December 2021 2022 2022
Oil volume (bopd) 42,462 33,095
Average \ufb02oor price protected ($/bbl) 51.37 55.00
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 18. Financial instruments continued
The following table demonstrates the hedge position as at 31 December 2022:
2023 hedge position at 31 December 2022 Bopd
Bought put
(\ufb02oor) Sold call
Bought
call
Hedge structure
Collars 33,095 $55.00 $74.62 \u2013
Zero cost dollars \u2013 \u2013 \u2013 \u2013
Straight Puts \u2013 \u2013 \u2013 \u2013
Total/weighted average 33,095 $55.00 $74.62 \u2013
2024 hedge position at 31 December 2022 Bopd
Bought put
(\ufb02oor) Sold call
Bought
call
Hedge structure
Collars 11,305 $55.00 $74.63 \u2013
Total/weighted average 11,305 $55.00 $74.63 \u2013
The following table demonstrates the sensitivity of the Group\u2019s derivative \ufb01nancial instruments to reasonably possible movements in
Dated Brent oil prices:
Effect on equity
Market
movement
as at
31 Dec 2022
2022
$m
2021
$m
Brent oil price 25% (464.4) (416.2)
Brent oil price (25%) \u2013 41.1
The following assumptions have been used in calculating the sensitivity in movement of the oil price: the pricing adjustments relate
only to the point forward mark-to-market (MTM) valuations, the price sensitivities assume there is no ineffectiveness related to the oil
hedges and the sensitivities have been run only on the intrinsic element of the hedge as Management considers this to be the material
component of oil hedge valuations.
Hedge reserve summary
The hedge reserve represents the portion of deferred gains and losses on hedging instruments deemed to be effective cash \ufb02ow
hedges. The movement in the reserve for the period is recognised in other comprehensive income.
The following table summarises the cash \ufb02ow hedge reserve by intrinsic and time value, net of tax effects:
Cash \ufb02ow hedge reserve
2022
$m
2021
$m
Oil derivatives \u2013 intrinsic (150.3) (39.5)
Oil derivatives \u2013 time value (94.4) (146.7)
The deferred gains and losses in the hedge reserve are subsequently transferred to the income statement at maturity of derivative
contracts. The tables below show the impact on the hedge reserve and on sales revenue during the year:
Deferred amounts in the hedge reserve \u2013 intrinsic
2022
$m
2021
$m
At 1 January (39.3) 4.8
Reclassi\ufb01cation adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue 288.5 112.3
Revaluation (losses)/gains arising in the year (399.5) (159.1)
Movement in current and deferred tax \u2013 2.7
(110.8) (44.3)
At 31 December (150.3) (39.3)
Note 18. Financial instruments continued
Hedge reserve summary
Deferred amounts in the hedge reserve \u2013 time value
2022
$m
2021
$m
At 1 January (146.9) (5.4)
Reclassi\ufb01cation adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue 30.8 40.7
Revaluation losses arising in the year 21.7 (182.3)
Movement in current and deferred tax \u2013 0.1
52.5 (141.5)
At 31 December (94.4) (146.9)
Reconciliation to sales revenue
2022
$m
2021
$m
Oil derivatives \u2013 transferred to sales revenue 288.5 112.3
Deferred premium paid 30.8 40.7
Net losses/(gain) from commodity derivatives in sales revenue (note 2) 319.3 153.0
Interest rate risk
Interest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market
interest rates. During part of the \ufb01nancial year 2021, the Group was exposed to interest rate risk as it borrowed funds at both \ufb01xed and
\ufb02oating interest rates. Following the debt re\ufb01nancing in May 2021, all of the Group\u2019s borrowings are \ufb01xed interest bearing. The Super
Senior Revolving Credit Facility is based on \ufb02oating interest rates and remains undrawn as at 31 December 2022.
Fixed rate debt comprises 2025 Notes and 2026 Notes.
The interest rate pro\ufb01le of the Group\u2019s \ufb01nancial assets and liabilities, excluding trade and other receivables and trade and other
payables, at 31 December 2022 and 2021, was as follows:
2022
Cash and cash
equivalents
$m
2022
Fixed rate
debt
$m
2022
Total
$m
2021
Cash and cash
equivalents
$m
2021
Fixed rate
debt
$m
2021
Total
$m
US$ 578.1 (2,500.0) (1,921.9) 376.2 (2,600.0) (2,223.8)
Euro 0.3 \u2013 0.3 1.3 \u2013 1.3
Sterling 16.3 \u2013 16.3 85.4 \u2013 85.4
XAF 38.8 \u2013 38.8 \u2013 \u2013
Other 2.8 \u2013 2.8 6.2 \u2013 6.2
636.3 (2,500.0) (1,863.7) 469.1 (2,600.0) (2,130.9)
Cash and cash equivalents consisted of $230.7 million (2021: $159.9 million) of deposits which earn interest at rates set in advance for
periods ranging from overnight to three months by reference to market rates.
The sensitivity of the Group\u2019s \ufb01nancial instruments to reasonably possible movements in interest rates is considered not material.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 18. Financial instruments continued
Credit risk
The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits
and speci\ufb01c transaction approvals. The Group limits its counterparty credit risk on cash and cash equivalent balances by dealing only
with \ufb01nancial institutions with credit ratings of at least A or equivalent.
The primary credit exposures for the Group are its receivables generated by the marketing of crude oil and amounts due from
JV Partners (including in relation to their share of the TEN FPSO lease). These exposures are managed at the corporate level.
The Group\u2019s crude sales are predominantly made to international oil market participants including the oil majors, trading houses
and re\ufb01neries. JV Partners are predominantly international major oil and gas market participants. Counterparty evaluations are
conducted utilising international credit rating agency and \ufb01nancial assessments. Where considered appropriate, security in the
form of trade \ufb01nance instruments from \ufb01nancial institutions with an appropriate credit rating, such as letters of credit, guarantees
and credit insurance, are obtained to mitigate the risks.
The Group generally enters into derivative agreements with banks which are lenders under the SSRCF. The Group does not have any
signi\ufb01cant credit risk exposure to any single counterparty or any group of counterparties. The maximum \ufb01nancial exposure due to
credit risk on the Group\u2019s \ufb01nancial assets, representing the sum of cash and cash equivalents, investments, derivative assets, trade
receivables, and receivables from Joint Venture Partners, as at 31 December 2022 was $1,438.7 million (2021: $1,609.6 million).
Foreign currency risk
The Group conducts and manages its business predominantly in US dollars, the functional currency of the industry in which it operates.
The Group also purchases the functional currencies of the countries in which it operates routinely on the spot market. From time to
time the Group undertakes transactions denominated in other currencies arising from certain operating and capital expenditure
incurred in currencies other than US dollars; these exposures are often managed by executing foreign currency \ufb01nancial derivatives.
There were no foreign currency \ufb01nancial derivatives in place as at 31 December 2022 (2021: nil). Cash balances are held in other
currencies to meet immediate operating and administrative expenses or to comply with local currency regulations.
As at 31 December 2022, the only material monetary assets or liabilities of the Group that were not denominated in the functional
currency of the respective subsidiaries involved were $58.1 million in non-US dollar-denominated cash and cash equivalents
(2021: $46.9 million).
The following table demonstrates the sensitivity of the Group\u2019s \ufb01nancial instruments to reasonably possible movements in US dollar
exchange rates:
Effect on pro\ufb01t before tax Effect on equity
Market movement
2022
$m
2021
$m
2022
$m
2021
$m
US$/foreign currency exchange rates 20% 9.7 (7.8) 9.7 (7.8)
US$/foreign currency exchange rates (20%) (14.5) 11.7 (14.7) 11.7
Liquidity risk
The Group manages its liquidity risk using both short-term and long-term cash \ufb02ow projections, supplemented by debt \ufb01nancing plans
and active portfolio management across the Group. Ultimate responsibility for liquidity risk management rests with the Board of
Directors, which has established an appropriate liquidity risk management framework covering the Group\u2019s short, medium and long-term
funding and liquidity management requirements.
The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different
scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets
and delays to development projects. The Group had $1.1 billion (2021: $0.9 billion) of total facility headroom and free cash as at
31 December 2022.
The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative \ufb01nancial liabilities with agreed repayment
periods. The tables have been drawn up based on the undiscounted cash \ufb02ows of \ufb01nancial liabilities based on the earliest date on which
the Group can be required to pay.
Note 18. Financial instruments continued
Foreign currency risk continued
Weighted
average
effective
interest rate
Less than
1 month
$m
1\u20133
months
$m
3 months
to 1 year
$m
1\u20135
years
$m
5+
years
$m
Total
$m
31 December 2022
Non-interest bearing n/a 93.5 \u2013 26.3 47.0 \u2013 166.8
Lease liabilities 7.1% 27.3 57.1 225.2 746.3 10.5 1,066.4
Fixed interest rate instruments 9.7%
Principal repayments \u2013 \u2013 100.0 2,400.0 \u2013 2,500.0
Interest charge \u2013 28.0 197.0 464.0 \u2013 689.0
Total 120.8 85.1 548.5 3,657.3 10.5 4,422.2
Weighted
average
effective
interest rate
Less than
1 month
$m
1\u20133
months
$m
3 months
to 1 year
$m
1\u20135
years
$m
5+
years
$m
Total
$m
31 December 2021
Non-interest bearing n/a 71.9 18.6 26.0 71.3 5.7 193.5
Lease liabilities 7.1% 44.4 52.7 217.2 950.3 16.4 1,281.0
Fixed interest rate instruments 9.7%
Principal repayments \u2013 \u2013 100.0 2,500.0 \u2013 2,600.0
Interest charge \u2013 28.0 207.0 689.0 \u2013 924.0
Total 116.3 99.3 550.2 4,210.6 22.1 4,998.5
Note 19. Leases
This note provides information for leases where the Group is a lessee. The Group did not enter into any contracts acting as a lessor.
i) Amounts recognised in the balance sheet
Right-of-use assets Lease liabilities
Right-of-use assets (included within property, plant and equipment) and lease liabilities
31 December
2022
$m
31 December
2021
$m
31 December
2022
$m
31 December
2021
$m
Property leases 39.2 34.8 34.6 41.0
Oil and gas production and support equipment leases 639.0 599.2 942.4 1,107.3
Transportation equipment leases 3.4 6.9 7.1 15.1
Total 681.6 640.9 984.1 1,163.4
Current 251.2 251.5
Non-current 732.9 911.9
Total 984.1 1,163.4
Additions to the right-of-use assets during the 2022 \ufb01nancial year were $63.5 million. Refer to note 10.
For ageing of lease liabilities, refer to note 18.
The Group\u2019s leases balance includes TEN FPSO, classi\ufb01ed as Oil and gas production and support equipment. As at 31 December 2022, the
present value of the TEN FPSO right-of-use asset was $596.9 million (2021: $561.6 million). The increase during the year is due to
additional interest in the FPSO following Ghana pre-emption, offset by the depreciation charge.
The present value of the TEN FPSO gross lease liability was $847.9 million (2021: $1,012.8 million).
A receivable from the Joint Venture Partners of $330.1 million (2021: $478.8 million) was recognised in other assets (note 11) to re\ufb02ect
the value of future payments that will be met by cash calls from partners relating to the TEN FPSO lease. The present value of the
receivable from the Joint Venture Partners unwinds over the expected life of the lease and the unwinding of the discount is reported
within \ufb01nance income.
Following discussions with the Joint Venture Partners, Tullow remeasured the Espoir FPSO lease liability to align the accounting
with the plan of the partnership to exercise the option to purchase the FPSO in March 2023 for a gross consideration of $20.0 million
($4.7 million net). This resulted in a decrease in the lease liability as at 31 December 2022 to $6.6 million (2021: $13.2 million), and the
in right of use asset to $nil (2021: $3.6 million) resulting in a gain on the lease remeasurement of $3.1 million recorded as Other gains
and losses in the income statement.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 19. Leases continued
i) Amounts recognised in the balance sheet continued
On 2 April 2021, the Group contracted Maersk Venturer offshore drilling rig to undertake the drilling work programme for Jubilee and
TEN \ufb01elds in Ghana. As at 31 December 2022, Tullow carries right-of-use assets of $31.2 million (2021: $25.8 million), and gross lease
liability of $64.9 million (2021: $59.9 million) as Tullow entered the lease on behalf of the Joint Venture. A receivable from Joint Venture
Partners of $32.0 million (2021: $33.0 million) has been recognised in other assets to re\ufb02ect the value of future payments that will be
met by cash calls from the Joint Venture Partners. The lease was initially recognised for an 18-month term, in line with the early
termination option included in the contract and approvals received by the partners. In July 2022 the contract was extended for a
12-month term ending September 2023.
Carrying amounts of the lease liabilities and joint venture leases receivables and the movements during the period:
Lease
liabilities
$m
Joint
Venture lease
receivables
$m
Total
$m
At 1 January 2021 (1,216.5) 541.0 (675.5)
Additions and changes in lease estimates (161.9) 93.7 (68.2)
Payments/ (receipts) 298.3 (142.4) 155.9
Interest (expense)/income (83.3) 38.7 (44.6)
At 1 January 2022 (1,163.4) 531.0 (632.4)
Additions and changes in lease estimates (89.4) 40.2 (49.2)
Acquisitions
1
\u2013 (86.6) (86.6)
Payments/ (receipts) 342.0 (138.2) 203.8
Interest (expense)/income (76.4) 29.6 (46.8)
Currency translation adjustments 3.1 \u2013 3.2
At 31 December 2022 984.1 376.1 608.0
1. This relates to an acquisition through business combination discussed in Note 15.
ii) Amounts recognised in the statement of pro\ufb01t or loss
Right-of-use assets (included within Property, plant and equipment)
31 December
2022
$m
31 December
2021
$m
Depreciation charge of right-of-use assets
Property leases 14.0 7.8
Oil and gas production and support equipment leases 46.9 52.8
Total 60.9 60.6
Interest expense on lease liabilities (included in \ufb01nance cost) 76.4 83.4
Interest income on amounts due from Joint Venture Partners (29.6) (38.8)
Expense relating to short-term leases 2.0 7.8
Expense relating to leases of low-value assets 1.8 1.0
Total 111.5 114.0
The total net cash out\ufb02ow for leases in 2022 was $203.8 million (2021: $155.9 million).
Note 20. Provisions
Notes
Decommissioning
2022
$m
Other
provisions
2022
$m
Total
2022
$m
Decommissioning
2021
$m
Other
provisions
2021
$m
Total
2021
$m
At 1 January 498.7 228.8 727.5 696.1 154.6 850.7
New provisions, changes in estimates and
reclassi\ufb01cations (47.6) (19.7) (67.3) (134.8) 90.0 (44.8)
Acquisitions
1
15 24.8 36.8 61.6 \u2013 \u2013 \u2013
Payments (72.1) (127.3) (199.4) (69.3) (15.7) (85.0)
Unwinding of discount 5 6.0 \u2013 6.0 7.6 \u2013 7.6
Currency translation adjustment (11.6) (2.3) (13.9) (0.9) (0.1) (1.0)
At 31 December 398.1 116.3 514.4 498.7 228.8 727.5
Current provisions 87.7 11.1 98.8 101.2 195.3 296.5
Non-current provisions 310.4 105.2 415.6 397.5 33.5 431.0
1. This relates to an acquisition through business combination discussed in note 15.
Other provisions include non-income tax provisions of $68.3 million (2021: $52.8 million) and $48.0 million (2021: $176.0 million) of
disputed cases and claims. Management estimates non-current other provisions would fall due between two and \ufb01ve years.
Non-Current other provisions mainly relates to Bangladesh litigation. Refer to Uncertain Tax Treatments in Accounting Policies.
This also includes a provision relating to a potential claim arising out of historical contractual agreement. Further information is not
provided as it will be seriously prejudicial to the Company\u2019s interest.
On 15 February 2022, an arbitration panel delivered an award against Tullow in respect to a historic contractual dispute in Norway
related to the acquisition of Spring Energy Norway AS (Spring) from HiTecVision V (HiTec). The Tribunal decided by way of split
decision that conditions under the Spring SPA in respect of the bonus payment had been met. The Tribunal ruled that Tullow should
pay $76 million to HiTec (an amount which includes interest and costs) and a further amount of $0.7 million in respect of Tribunal
costs. This balance was provided for as at 31 December 2021 and was settled in March 2022.
The decommissioning provision represents the present value of decommissioning costs relating to the European and African oil and
gas interests. The Group has assumed cessation of production as the estimated timing for out\ufb02ow of expenditure. However expenditure
could be incurred prior to cessation of production or after and actual timing will depend on a number of factors including, underlying
cost environment, availability of equipment and services and allocation of capital.
In 2022, the Group has increased the decommissioning discount rate by 1.5-2% from 31 December 2021 due to movement in the risk-free
rate. This resulted in a decrease of the provision by $39.5 million in Ghana, $15.6 million in C\u00f4te d\u2019Ivoire and $12.1 million in Gabon.
In\ufb02ation
assumption
1
Discount
rate
assumption
2022
Cessation of
production
assumption
2022
Total
2022
$m
Discount rate
assumption
2021
Cessation of
production
2021
Total
2021
$m
C\u00f4te d\u2019Ivoire 2% 3.5% 2035 45.6 1.5% 2033 61.7
Gabon 2% 3.5% 2025-2037 49.2 1.5-2% 2026-2036 61.9
Ghana 2% 3.5% 2036 190.2 1.5-2% 2035-2036 193.3
Mauritania n/a n/a 2018 56.0 n/a 2018 61.6
UK n/a n/a 2018 57.1 n/a 2018 120.2
398.1 498.7
1. Short term in\ufb02ation rate assumption has increased from 2% to 4.7% in 2023 and to 2.5% in 2024. Medium and long-term rates of 2% remained unchanged from
31 December 2021.
The Group's decommissioning activities are ongoing in the UK and Mauritania and majority of the future costs is expected to be
incurred in 2023 ($87.4 million). The remaining activities are planned to continue through to 2027, with an associated expenditure
of $25.7 million.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 21. Deferred taxation
Accelerated
tax
depreciation
$m
Decommissioning
$m
Tax
losses
$m
Other
temporary
differences
$m
Provision for
onerous
service
contracts
$m
Deferred
petroleum
revenue tax
$m
Total
$m
At 1 January 2021 (645.7) 105.6 335.7 (8.4) 21.7 12.1 (179.0)
Credit/(charge) to income statement 46.8 (16.5) (113.8) (58.7) \u2013 (2.7) (144.9)
Transfer to disposals 0.6 (0.2) \u2013 0.7 \u2013 \u2013 1.1
Exchange differences \u2013 (0.1) \u2013 \u2013 \u2013 \u2013 (0.1)
At 1 January 2022 (598.3) 88.8 221.9 (66.4) 21.7 9.4 (322.9)
Credit/(charge) to income statement 184.0 (22.9) (186.1) (32.6) (5.9) (5.0) (68.5)
Acquired through business combination
(note 15) (143.6) \u2013 \u2013 \u2013 \u2013 \u2013 (143.6)
Exchange differences (0.2) \u2013 \u2013 \u2013 \u2013 (1.8) (2.0)
At 31 December 2022 (558.1) 65.9 35.8 (99.0) 15.8 2.6 (537.0)
2022
$m
2021
$m
Deferred tax liabilities (551.5) (677.3)
Deferred tax assets 14.5 354.4
(537.0) (322.9)
The majority of the Group's deferred tax assets and liabilities are expected to be recovered over more than one year.
Deferred tax assets are recognised only to the extent it is considered probable that those assets will be recoverable. This involves
an assessment of when those deferred tax assets are likely to reverse, and a judgement as to whether or not there will be sufficient
taxable pro\ufb01ts available to offset the tax assets when they do reverse. This requires assumptions regarding future pro\ufb01tability and is
therefore inherently uncertain. To the extent assumptions regarding future pro\ufb01tability change, there can be an increase or decrease
in the level of deferred tax assets recognised which can result in a charge or credit in the period in which the change occurs.
Note 22. Called-up equity share capital and share premium account
Allotted equity share capital and share premium
Equity share capital
allotted and fully paid Share premium
Number $m $m
Ordinary shares of 10p each
At 1 January 2021 1,414,071,777 211.7 1,294.7
Issued during the year
Exercise of share options 18,008,320 2.5 \u2013
At 1 January 2022 1,432,080,097 214.2 1,294.7
Issued during the year
Exercise of share options 7,525,898 1.0 \u2013
At 31 December 2022 1,439,605,995 215.2 1,294.7
The Company does not have a maximum authorised share capital.
Note 23. Share-based payments
Analysis of share-based payment charge
Notes
2022
$m
2021
$m
Tullow Incentive Plan 3.9 8.1
Employee Share Award Plan 1.2 3.0
2022 PDME Buyout Award 0.5 0.5
2021 Tullow Sharesave Plan 0.2 \u2013
5.8 11.6
Expensed to operating costs 4 0.4 0.5
Expensed as administrative cost 4 5.4 11.1
Total share-based payment charge 5.8 11.6
The national insurance liability as at 31 December 2022 was $1.6 million (2021:$1.3 million)
Tullow Incentive Plan (TIP)
Under the TIP, Senior Management can be granted nil exercise price options, normally exercisable from three years (\ufb01ve years in
the case of the Company\u2019s Directors) to ten years following grant provided an individual remains in employment. The size of awards
depends on both annual performance measures and total shareholder return (TSR) over a period of up to three years. There are no
post-grant performance conditions. No dividends are paid over the vesting period; however, it has been agreed for the TIP Awards
since 2018 that an amount equivalent to the dividends that would have been paid on the TIP shares during the vesting period if they
were \u2018real\u2019 shares will also be payable on exercise of the award. There are further details of the TIP in the Remuneration Report on
pages 73 to 97.
The weighted average remaining contractual life for TIP awards outstanding at 31 December 2022 was 4.9 years.
Employee Share Award Plan (ESAP)
Most Group employees are eligible to be granted nil exercise price options, that are exercisable from three to ten years following grant.
An individual must normally remain in employment for three years from grant for the share to vest. Awards are not subject to post-grant
performance conditions. No dividends are paid over the vesting period; however, it has been agreed for the ESAP awards granted
since 2018 it was agreed that an amount equivalent to the dividends that would have been paid on the ESAP shares during the vesting
period if they were \u2018real\u2019 shares will also be payable on exercise of the award.
Phantom options that provide a cash bonus equivalent to the gain that could be made from a share option (being granted over a
notional number of shares) have also been granted under the ESAP in situations where the grant of share options was not practicable.
The weighted average remaining contractual life for ESAP awards outstanding at 31 December 2022 was 6.7 years.
2010 Share Option Plan (2010 SOP)
Participation in the 2010 SOP was available to most of the Group\u2019s employees. Options have an exercise price equal to market value shortly
before grant and are normally exercisable between three and ten years from the date of the grant subject to continuing employment.
Phantom options, providing a cash bonus equivalent to the gain that could be made from a share option, have also been granted under
the 2010 SOP in situations where the grant of share options was not practicable.
Outstanding options under the SOP at 31 December 2022 had exercise prices of 900p to 1,039p (2021: 900p to 1,294p) and remaining
contractual lives between 53 days and 219 days. The weighted average remaining contractual life is 0.3 years.
2020 PDMR Buyout Awards
On 5 August 2020, the Company granted the new Chief Executive Officer a number of Buyout Awards following the commencement
of their employment in order to compensate them for certain share arrangements forfeited upon leaving their former employer. The
grant of the awards was conditional on the CEO purchasing shares in the Company with a value of \u00a3350,000 (the \u2018Purchased Shares\u2019).
These awards will vest after \ufb01ve years from the date of joining subject to continued service and the retention of the Purchased Shares.
The awards comprise: a restricted share award in the form of a nil-cost option over 3,000,000 shares; a share option over 3,000,000
shares with a per share exercise price of \u00a30.2566 (being equal to the market value of a share at the close of trading on the dealing date
immediately following the date on which the Purchased Shares were acquired); and a share option over 3,000,000 shares with a per
share exercise price of \u00a30.5132 (being twice the exercise price for the above options).
The awards will ordinarily vest on 1 July 2025 and if they remain unexercised will expire on 1 July 2030. There are further details of the
2020 PDMR Buyout Awards in the Remuneration Report on pages 73 to 97.
The weighted average remaining contractual life for the PDMR Buyout Awards outstanding at 31 December 2022 was 7.5 years.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 23. Share-based payments continued
2021 Tullow Sharesave Plan (SAYE)
UK based employees are eligible to participate in the SAYE scheme introduced in 2021. These are standard statutory HMRC approved
\u2018Save as you earn\u2019 awards. To participate in the SAYE, employees choose how much money of their net salary to save each month
(subject to certain limits) for a period of three years. At the end of the period employees are entitled to purchase share using the funds
they have saved at a price 20% below the market price on the day before the invitation date. Alternatively, they can elect to take back
all their savings as cash. Only employees who remain in service and continue to pay monthly contributions will be eligible to purchase
shares. If they leave employment or choose to stop paying contributions before the end of the three-year period they will be refunded
the amount they have saved.
Outstanding SAYE awards at 31 December 2022 had exercise prices of 38p to 40p and remaining contractual lives between 2.4 years
and 3.4 years. The weighted average remaining contractual life is 2.8 years.
UK and Irish Share Incentive Plans (SIPs)
These are all-employee plans set up in the UK and Ireland, to enable employees to save out of salary up to prescribed monthly limits.
Contributions are used by the SIP trustees to buy Tullow shares (Partnership Shares) at the end of each three-month accumulation
period. The Company makes a matching contribution to acquire Tullow shares (Matching Shares) on a one-for-one basis. Under the
UK SIP, Matching Shares are subject to time-based forfeiture over three years on leaving employment in certain circumstances or if
the related Partnership Shares are sold. The fair value of a Matching Share is its market value when it is awarded.
Under the UK SIP: (i) Partnership Shares are purchased at the lower of their market values at the start of the accumulation period and
the purchase date (which is treated as a three-month share option for IFRS 2 purposes and therefore results in an accounting charge);
and (ii) Matching Shares vest over the three years after being awarded (resulting in their accounting charge being spread over that period).
Under the Irish SIP: (i) Partnership Shares are bought at the market value at the purchase date (which does not result in any
accounting charge); and (ii) Matching Shares vest over the two years after being awarded (resulting in their accounting charge being
spread over that period).
The following table illustrates the number and average weighted share price at grant or weighted average exercise price (WAEP) of,
and movements in, share options under the TIP, ESAP, 2010 SOP, 2020 buyout and SAYE.
Outstanding
as at
1 January
Granted
during
the year
Exercised
during
the year
Forfeited/
expired during
the year
Outstanding
at
31 December
Exercisable
at
31 December
2022 TIP \u2013 number of shares
21,740,803 8,076,264 4,529,667 433,152 24,854,248 3,014,253
2022 TIP \u2013 average weighted share price
at grant 105.3 49.1 211.6 64.4 68.4 220.0
2021 TIP \u2013 number of shares 28,116,828 2,488,749 8,191,155 673,619 21,740,803 2,054,238
2021 TIP \u2013 average weighted share price
at grant 133.0 60.5 188.8 81.8 105.3 191.2
2022 ESAP \u2013 number of shares 17,638,898 3,556,316 2,803,974 1,061,163 17,330,077 4,613,422
2022 ESAP \u2013 average weighted share price
at grant
96.5 49.3 180.0 45.2 76.4 228.5
2021 ESAP \u2013 number of shares 29,919,699 \u2013 9,462,175 2,818,626 17,638,898 5,181,246
2021 ESAP \u2013 average weighted share price
at grant 126.1 \u2013 198.4 67.8 96.5 213.4
2022 SOP \u2013 number of shares
2,046,755 \u2013 \u2013 1,868,472 178,283 178,283
2022 SOP \u2013 WAEP 1,106.0 \u2013 \u2013 1,118.4 976.4 976.4
2021 SOP \u2013 number of shares 5,943,263 \u2013 \u2013 3,896,508 2,046,755 2,046,755
2021 SOP \u2013 WAEP 1,124.6 \u2013 \u2013 1,134.4 1,106.0 1,106.0
2022 Buyout Awards \u2013 number of shares 9,000,000 \u2013 \u2013 \u2013 9,000,000 \u2013
2022 Buyout Awards \u2013 WAEP 25.7 \u2013 \u2013 \u2013 25.7 \u2013
2021 Buyout Awards \u2013 number of shares 9,000,000 \u2013 \u2013 \u2013 9,000,000 \u2013
2021 Buyout Awards \u2013 WAEP 25.7 \u2013 \u2013 \u2013 25.7 \u2013
2022 SAYE \u2013 number of options 1,534,241 975,600 \u2013 121,970 2,387,871 \u2013
2022 SAYE \u2013 WAEP 38.0 40.0 \u2013 38.2 38.8 \u2013
2021 SAYE \u2013 number of options \u2013 1,534,241 \u2013 \u2013 1,534,241 \u2013
2021 SAYE \u2013 WAEP \u2013 38.0 \u2013 \u2013 38.0 \u2013
The options granted during the year were valued using a proprietary binomial valuation.
Note 23. Share-based payments continued
The following table details the weighted average fair value of awards granted and the assumptions used in the fair value expense calculations.
2022 ESAP 2022 TIP 2021 TIP 2022 SAYE 2021 SAYE
Weighted average fair value of awards granted 49.3p 49.1p 60.5p 23.1p 34.8p
Principal inputs to options valuations model:
Weighted average share price at grant 49.3p 49.1p 60.5p 38.4p 53.6p
Weighted average exercise price 0.0p 0.0p 0.0p 40.0p 38.0p
Risk-free interest rate per annum
1
1.5% to 4.4% 1.5%/1.5% 0.1%/0.4% 4.3% 0.7%
Expected volatility per annum
1, 2
101% to 102% 102%/85% 101%/85% 91% 92%
Expected award life (years)
1, 3
3.0 3.0/5.0 3.0/5.0 3.6 3.6
Dividend yield per annum
4
n/a n/a n/a 0.0% 0.0%
Employee turnover before vesting per annum
1
5% 5%/0% 5%/0% 5% 5%
1. Shows the assumption for 2022 and 2021 TIP awards made to Senior Management/Executives and Directors respectively.
2. Expected volatility was determined by calculating the historical volatility of the Company\u2019s share price over a period commensurate with the expected life of the awards.
The fair values of the 2022 ESAP and TIP Awards, and the 2021 TIP Awards are not affected by the assumption for the Company\u2019s share price volatility.
3. The expected life is the average expected period from date of grant to exercise allowing for the Company\u2019s best estimate of participants\u2019 expected exercise behaviour.
4. No dividend yield assumption is needed for the fair value calculations for the 2022 ESAP and TIP Awards as a dividend equivalent will be payable on the exercise of these awards.
Note 24. Commitments and contingencies
2022
$m
2021
$m
Capital commitments 301.2 169.9
Contingent liabilities
Performance guarantees 84.1 100.8
Other contingent liabilities 55.8 14.0
139.9 114.8
Where Tullow acts as operator of a Joint Venture the capital commitments reported represent Tullow\u2019s net share of these commitments.
Where Tullow is non-operator the value of capital commitments is based on committed future work programmes.
Performance guarantees are in respect of abandonment obligations, committed work programmes and certain \ufb01nancial obligations.
Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash
out\ufb02ow to be higher than remote but not probable. The timing of any economic out\ufb02ow if it were to occur would likely range between
one and \ufb01ve years.
The movement in capital commitments is predominantly due to certain equipment costs being classi\ufb01ed as capital expenditure following
the transition of operatorship to Tullow on the Jubilee FPSO in 2022. These were previously recognised as operating expenses. In
addition, Tullow's equity interest increased following Ghana pre-emption.
Note 25. Related party transactions
The Directors of Tullow Oil plc are considered to be the only Key Management Personnel as de\ufb01ned by IAS 24 Related Party Disclosures.
2022
$m
2021
$m
Short term employee bene\ufb01ts 2.5 3.9
Post-employment bene\ufb01ts 0.1 0.3
Share-based payments 1.4 1.8
4.0 6.0
Short-term employee bene\ufb01ts
These amounts comprise fees paid to the Directors in respect of salary and bene\ufb01ts earned during the relevant \ufb01nancial year, plus
bonuses awarded for the year.
Post-employment bene\ufb01ts
These amounts comprise amounts paid into the pension schemes of the Directors.
Share-based payments
This is the cost to the Group of Directors\u2019 participation in share-based payment plans, as measured by the fair value of options and
shares granted, accounted for in accordance with IFRS 2 Share-based Payment.
There are no other related party transactions. Further details regarding transactions with the Directors of Tullow Oil plc are disclosed
in the Remuneration Report on pages 73 to 97.
26. Climate change and energy transition
In March 2021, Tullow announced its commitment to being Net Zero on our Scope 1 and Scope 2 emissions on a net equity basis
by 2030 supporting the goal of limiting global temperature rise to well below 2o C as per Article 2 of the Paris Agreement.
This note describes how Tullow has considered climate related impacts in some key areas of the \ufb01nancial statements and how this
translates into the valuation of assets and measurement of liabilities as Tullow make progress in the energy transition.
Note (ag) key sources of estimation uncertainties describes those uncertainties that have the potential to have a material effect on
the Group Balance Sheet in the next 12 months.
This note describes the key areas of climate impacts that potentially have short and longer-term effects on amounts recognised in
the Group Balance Sheet as at 31 December 2022. Where relevant this note contains references to other notes to the Group Financial
Statements and aims to provide an overarching summary.
Financial planning assumptions
Tullow targets being Net Zero scope 1 and 2 emissions by 2030, compared to 2020 levels on a net equity basis, and at least 40%
reduction in GHG by 2025 have been included in Tullow\u2019s business plans. The \ufb01nancial statements are based on reasonable and
supportable assumptions that represent management\u2019s current best estimate of the range of economic conditions that may exist in
the foreseeable future.
The Group has performed an assessment of the potential future impact of Climate Change on key elements of its Financial Statements
utilising three IEA scenarios (see page 23 for details). Tullow continues to assess the impact to operating cash \ufb02ow (OCF) on our
currently producing assets using the oil price assumptions within the IEA scenarios. We focused our assessment on impacts to
OCF for our existing production portfolio over 1, 5, and 10 years consistent with our Viability Statement. It is clear from the oil price
trajectories in the revised APS and NZE scenarios that the IEA predicts a more challenging oil price environment should the
assumptions within these scenarios come to pass.
Tullow\u2019s corporate oil price planning assumption is generally higher than the IEA Scenarios, with the exception of the STEPS
scenario from 2024 onward. Given the STEPS scenario is a conservative benchmark for future oil prices, re\ufb02ecting global policies
and implementing measures adopted as of the end September 2022, we consider our current planning assumptions, informed
by a range of broker and consultant forecasts, to be a fair consideration of oil market conditions over the medium term.
We also assess acute and chronic physical climate impacts on our existing assets and incorporate meteorological and climate
conditions into operational design considerations, with support from external consultant- Verisk Maplecroft in 2019. This process
identi\ufb01ed a potential exposure related to consumables stored at Ghana onshore facility, though the related \ufb01nancial impact was
deemed insigni\ufb01cant. The physical effects of climate change have also been taken into consideration for core operated asset
locations in Ghana, Guyana and Kenya. Analysis suggests exposure to physical risks is relatively minimal in comparison to historical
conditions, however there is risk of increasing extremes in cyclical precipitation and drought events onshore Kenya. We will continue
to monitor and assess our assets\u2019 exposure to physical climate risks and will evolve our understanding of the potential transmission
pathways of climate-related risks and related costs which may affect our operations, strategy or performance including through our
supply chain.
Similarly, while carbon prices are projected to grow there is low likelihood that a compliance carbon pricing mechanism, such as a
carbon tax or emissions trading scheme, will be formalised in our core geographies, and not before Tullow\u2019s Scope 1 and 2 emissions
have peaked (before 2025). Tullow reviewed and revised its internal shadow carbon price to $25/tCO2e in line with the NZE carbon
price for other emerging market and developing economies, which we see as a robust but realistic carbon price assumption for host
nations where we have producing assets. Based on the forecast emissions pro\ufb01le of our portfolio in 2030, the majority of which is
from emissions associated with our Ghana production assets, we calculate a potential annual carbon price sensitivity of $12.5 million.
To mitigate our residual, hard to abate emissions we are developing a nature based carbon offset project with the Forestry
Commission of Ghana. We will have more visibility of the future costs of the project as we progress towards FID in 2023. The carbon
price sensitivity or costs for nature based carbon offset projects are not included in the value in use calculation of the recoverable
amount of the Group CGUs as these are considered as corporate costs.
Pricing assumptions used will continue to be updated for changes in the economic environment and the pace of the energy transition.
Tullow will continue to use the \u201cNet Zero Emissions by 2050 Scenario\u201d to assess potential \ufb01nancial impacts to the following:
Intangible exploration and evaluation assets
The \u201cNet Zero Emissions by 2050 Scenario\u201d represents a challenging oil price environment for future exploration and development
investments, particularly post 2030 when the bulk of the cash \ufb02ows would be generated from these types of projects. Therefore, this
could result in a potential write-off of all of the $253 million net book value if the assumptions within the NZE scenario were to arise.
Property, plant and equipment
The Group has included the costs in its impairment assessment directly attributable to CGU\u2019s associated with its Net Zero plans.
The \u201cNet Zero Emission by 2050 Scenario\u201d would trigger reductions in cash \ufb02ows of between 0\u201310%. Speci\ufb01cally, if the \u201cNet Zero
emission by 2050 scenario\u201d were to arise the Group would recognise an additional impairment of $654 million. As stated above the
Group does not expect a material impact on any other balance sheet line item as a result of the IEA scenarios.
26. Climate change and energy transition continued
Decommissioning provision
The energy transition could result in decommissioning taking place earlier than anticipated. The risk on the timing of
decommissioning activities is limited, supported by production plans to fully produce \ufb01elds in the foreseeable future. The discount
rate used to discount decommissioning provision is between 10-15-years term in line with the average remaining life of our producing
assets. Under the \"Net Zero Emission by 2050 Scenario\" cessation of production assumptions would accelerate by; Ghana 0-7 years,
Gabon 0-8 years and C\u00f4te d\u2019Ivoire
7 years.
Governmental and societal responses to climate change risks are still developing, and are interdependent upon each other, and
consequently \ufb01nancial statements cannot capture all possible future outcomes as these are not yet known.
Note 27. Events since 31 December 2022
Non adjusting events
Throughout 2021 and 2022, Tullow has received revised and new tax assessments from the Ghana Revenue Authority (GRA) resulting in
a combined potential exposure of c.$1 billion. Tullow believes these assessments are without merit and \ufb01led requests for arbitration
with the International Chamber of Commerce in London, in accordance with the dispute resolution process set out in the Petroleum
Agreements which govern Tullow Ghana Limited\u2019s activities in Ghana. Notwithstanding this formal step, Tullow intends to continue to
engage with the Government of Ghana, including the GRA, with the aim of resolving these disputes on a mutually acceptable basis.
In March 2023, Tullow and its JV Partners submitted an updated Field Development Plan to the Ministry of Energy and Petroleum
and the Energy and Petroleum Regulatory Commission Authority in Kenya, for their approval. This is currently under review by the
relevant authorities.
In 2023, there were two new appointments:
Richard Miller appointed as Chief Financial Officer (CFO) from January 2023.
Roald Goethe appointed as independent non-executive Director from February 2023.
There have not been any other events since 31 December 2022 that have resulted in a material impact on the year end results.
Note 28. Cash \ufb02ow statement reconciliations
Purchases of intangible exploration and evaluation assets
2022
$m
2021
$m
Additions to intangible exploration and evaluation assets 39.2 46.3
Associated cash \ufb02ows
Purchases of intangible exploration and evaluation assets (42.6) (86.1)
Non-cash movements/presented in other cash \ufb02ow lines
Movement in working capital 3.4 39.8
Purchases of property, plant and equipment
2022
$m
2021
$m
Additions to property, plant and equipment 370.7 148.1
Associated cash \ufb02ows
Purchases of property, plant and equipment (263.8) (150.4)
Non-cash movements/presented in other cash \ufb02ow lines
Decommissioning asset revisions 19.9 134.8
Right-of-use asset additions (63.5) (73.5)
Movement in working capital (63.3) (59.0)
Movement in borrowings
2022
$m
2021
$m
2020
$m
2022
Movement
2021
Movement
Borrowings 2,472.8 2,568.7 3,170.5 (95.9) (601.8)
Associated cash \ufb02ows
Debt arrangement fees \u2013 (56.6)
Repayment of borrowings (100.0) (2,379.9)
Drawdown of borrowings \u2013 1,800.0
Non-cash movements/presented in other cash \ufb02ow lines
Amortisation of arrangement fees and accrued interest 4.1 34.7
Note 29. Dividends
In 2022, the Board recommended that no interim or \ufb01nal dividend would be paid.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 30. Tullow Oil plc subsidiaries
As at 31 December 2022
Each undertaking listed below is a subsidiary by virtue of Tullow Oil plc holding, directly or indirectly, a majority of voting rights in the
undertaking. The ownership percentages are equal to the effective equity owned by the Group. Unless otherwise noted, the share
capital of each undertaking comprises ordinary shares or the local equivalent thereof.
The percentage of equity owned by the Group is 100% unless otherwise noted. The results of all undertakings listed below are fully
consolidated in the Group\u2019s Financial Statements.
Company name Country of incorporation
Direct or
indirect Address of registered office
Hardman Oil and Gas Pty Ltd\u00b9 Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia
Hardman Resources Pty Ltd Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia
Tullow Chinguetti Production Pty Ltd Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia
Tullow Petroleum (Mauritania) Pty Ltd Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia
Tullow Uganda Holdings Pty Ltd\u00b2 Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia
Tullow Uganda Operations Pty Ltd Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia
Eagle Drill Limited
British Virgin Islands Indirect
(50%)
Akara Building, 24 De Castro Street, Wickhams Cay,
Road Town, Tortola, British Virgin Islands
Tullow (EA) Holdings Limited British Virgin Islands Indirect Ritter House, Wickhams Cay, Tortola, VG1110,
British Virgin Islands
DWT-T Company Cayman Islands Indirect PO Box 32322, 4th Floor Century Yard, Cricket Square,
George Town, KY1-1209, Cayman Islands
Planet Oil International Limited\u00b3 England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Argentina Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Comoros Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow C\u00f4te d\u2019Ivoire Onshore Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Group Services Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Jamaica Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow New Ventures Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Mozambique Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Oil 100 Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Oil 101 Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Oil Finance Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Oil SK Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Oil SPE Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Peru Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Technologies Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Uruguay Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Oil Gabon SA Gabon Indirect Quartier Tahiti, Immeuble Narval B.P. 9773,
Libreville, Gabon
Note 30. Tullow Oil plc subsidiaries continued
As at 31 December 2022 continued
Company name Country of incorporation
Direct or
indirect Address of registered office
Tullow Gabon Limited Isle of Man Indirect First Names House, Victoria Road, Douglas
IM2 4DF, Isle of Man
Tullow Oil (Mauritania) Ltd Guernsey Indirect P.O. Box 119, Martello Court, Admiral Park,
St. Peter Port GY1 3HB, Guernsey
Tullow Oil Holdings (Guernsey) Ltd\u2074 Guernsey Indirect P.O. Box 119, Martello Court, Admiral Park,
St. Peter Port GY1 3HB, Guernsey
Tullow Oil Limited Ireland Direct Number 1, Central Park, Leopardstown, Dublin 18,
Ireland
Tullow Congo Limited Isle of Man Indirect First Names House, Victoria Road, Douglas
IM2 4DF, Isle of Man
Tullow Gabon Holdings Limited Isle of Man Indirect First Names House, Victoria Road, Douglas
IM2 4DF, Isle of Man
Tullow Mauritania Limited Isle of Man Indirect First Names House, Victoria Road, Douglas
IM2 4DF, Isle of Man
Tullow Namibia Limited Isle of Man Indirect First Names House, Victoria Road, Douglas
IM2 4DF, Isle of Man
Tullow Uganda Limited Isle of Man Indirect First Names House, Victoria Road, Douglas
IM2 4DF, Isle of Man
Tullow C\u00f4te d\u2019Ivoire Exploration Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey
Tullow C\u00f4te d\u2019Ivoire Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Ghana Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey
Tullow India Operations Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Oil (Jersey) Limited Jersey Direct 44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Oil International Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Ethiopia BV Netherlands Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Guyana BV Netherlands Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Hardman Holdings BV Netherlands Indirect Prinses Margrietplantsoen 33, 2595AM
\u2018s-Gravenhage, The Netherlands
Tullow Kenya BV Netherlands Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Netherlands Holding Cooperatief BA\u2075 Netherlands Indirect Prinses Margrietplantsoen 33, 2595AM
\u2019s-Gravenhage, The Netherlands
Tullow Overseas Holdings BV Netherlands Direct 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Suriname BV Netherlands Indirect Prinses Margrietplantsoen 33, 2595AM
\u2019s-Gravenhage, The Netherlands
Tullow Uganda Holdings BV Netherlands Indirect Prinses Margrietplantsoen 33, 2595AM
\u2019s-Gravenhage, The Netherlands
Tullow Zambia BV Netherlands Indirect 9 Chiswick Park, 566 Chiswick High Road, London
W4 5XT, United Kingdom
Tullow Oil Norge AS Norway Indirect Tordenskioldsgate 6B, 0160 Oslo, Norway
Energy Africa Bredasdorp (Pty) Ltd South Africa Indirect 11th Floor, Convention Tower, Heerengracht Street,
Foreshore, Cape Town 8001, South Africa
Tullow South Africa (Pty) Limited South Africa Indirect 11th Floor, Convention Tower, Heerengracht Street,
Foreshore, Cape Town 8001, South Africa
T.U. S.A. Uruguay Indirect Colonia 810, Of. 403, Montevideo, Uruguay
1. Dissolved in October 2022.
2. Dissolved in October 2022.
3. Dissolved in December 2022.
4. Dissolved in March 2022.
5. Dissolved in January 2023.
Notes to the Group Financial Statements continued
Year ended 31 December 2022
Note 31. Licence interests
Current exploration, development and production interests
Ghana
Licence/Unit area Fields
Area
sq km
Tullow
interest Operator Other partners
Deepwater Tano
TEN Development Area
1
Jubilee, Wawa, Tweneboa,
Enyenra, Ntomme
619 54.84% Tullow Kosmos, KEGIN, GNPC,
Jubilee Oil Holdings, Petro SA
West Cape Three Points Jubilee 150 25.66% Tullow Kosmos, KEGIN, GNPC,
Jubilee Oil Holdings, Petro SA
Jubilee Field Unit Area
2
Jubilee, Mahogany, Teak 38.97% Tullow Kosmos, GNPC, Petro SA
1. GNPC has exercised its right to acquire an additional 5% in TEN. Tullow's interest is 54.84% after successfully pre-empting on Kosmos' purchase of Occidental
Petroleum's stake in both assets.
2. A unitisation agreement covering the Jubilee \ufb01eld was agreed by the partners of the West Cape Three Points and the Deepwater Tano licences. The Jubilee Unit Area
was expanded in 2017 to include the Mahogany and Teak \ufb01elds. It now includes all of the remaining part of the West Cape Three Points licence and a small part of the
Deepwater Tano licence.
Non-operated
Licence/Unit area Fields
Area
sq km
Tullow
interest Operator Other partners
C\u00f4te d\u2019Ivoire
CI-26 Special Area \u2018E\u2019 Espoir 235 21.33% CNR Petroci
Gabon
Avouma Avouma, South Tchibala 52 7.50% Vaalco Addax (Sinopec), Sasol, PetroEnergy
Ebouri Ebouri 15 7.50% Vaalco Addax (Sinopec), Sasol, PetroEnergy
Echira Echira 76 40.00% Perenco Gabon Oil Company
Etame Etame, North Tchibala 49 7.50% Vaalco Addax (Sinopec), Sasol, PetroEnergy
Ezanga 5,626 8.57% Maurel & Prom
Gwedidi Gwedidi 5 7.50% Maurel & Prom Gabon Oil Company
Limande Limande 54 40.00% Perenco Gabon Oil Company
Mabounda Mabounda 6 7.50% Maurel & Prom Gabon Oil Company
Maroc Maroc 17 7.50% Maurel & Prom Gabon Oil Company
Maroc Nord Maroc Nord 17 7.50% Maurel & Prom Gabon Oil Company
Mbigou Mbigou 5 7.50% Maurel & Prom Gabon Oil Company
M'Oba M'Oba 57 24.31% Perenco Gabon Oil Company
Niembi Niembi 4 7.50% Maurel & Prom Gabon Oil Company
Niungo Niungo 96 40.00% Perenco Gabon Oil Company
Oba Oba 44 10.00% Perenco Gabon Oil Company
Omko Omko 16 7.50% Maurel & Prom Gabon Oil Company
Onal Onal 46 7.50% Maurel & Prom Gabon Oil Company
Simba Simba 315 57.50% Perenco
Tchatamba Marin Tchatamba Marin 30 25.00% Perenco ONE-Dyas BV
Tchatamba South Tchatamba South 40 25.00% Perenco ONE-Dyas BV
Tchatamba West Tchatamba West 25 25.00% Perenco ONE-Dyas BV
Turnix Turnix 18 27.50% Perenco Gabon Oil Company
Note 31. Licence interests continued
Kenya
Licence Fields
Area
sq km
Tullow
interest Operator Other partners
Kenya
Block 10BA 11,569 50.00% Tullow Centric Energy, TotalEnergies
Block 10BB Amosing, Ngamia 6,172 50.00% Tullow Africa Oil, TotalEnergies
Block 12B 6,200 100.00% Tullow
Block 13T Ekales, Twiga 4,719 50.00% Tullow Africa Oil, TotalEnergies
Exploration
Licence/Unit area Fields
Area
sq km
Tullow
interest Operator Other partners
Argentina
Block MLO-114 5,942 40.00% Tullow Pluspetrol, Wintershall Dea
Block MLO-119 4,546 40.00% Tullow Pluspetrol, Wintershall Dea
Block MLO-122 4,420 100.00% Tullow
C\u00f4te d\u2019Ivoire
CI-524 551 90.00% Tullow Petroci
CI-803 1,345 90.00% Tullow Petroci
Guyana
Kanuku 4,154 37.50% Repsol TOQAP
Orinduik 1,776 60.00% Tullow TOQAP, Eco Atlantic O&G
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"fact-348": {
"value": "(b) Adoption of new and revised standards New International Financial Reporting Standards adopted The Group has applied the following standards and amendments for the \ufb01rst time for their annual reporting period commencing 1 January 2022: - Onerous Contracts \u2013 Costs of Ful\ufb01lling a Contract \u2013 Amendments to IAS 37; - IFRS 9 Financial Instruments \u2013 Fees in the '10 per cent' test for derecognition of \ufb01nancial liabilities'; - Reference to Conceptual Framework \u2013 Amendments to IFRS 3; and - Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16. The amendments listed above did not have any impact on the amounts recognised in prior periods and are not expected to signi\ufb01cantly affect the current or future periods. Upcoming International Financial Reporting Standards not yet adopted Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for 31 December 2022 reporting periods and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions. ",
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"fact-349": {
"value": "(c) Changes in accounting policy The Group has revised its accounting policy in relation to the presentation of corporate income taxes in Gabon and C\u00f4te d\u2019Ivoire Production Sharing Contracts (PSCs). Under the terms of the PSCs the share of the pro\ufb01t oil which the government is entitled to is deemed to include the notional corporate income tax which is paid by the government on behalf of Tullow. From 1 January 2022 the notional corporate income tax is classi\ufb01ed as an income tax in accordance with IAS 12 Income taxes which has resulted in a gross up of revenue with a corresponding increase in income tax expense. In the previous years, the Revenues and Taxes from Gabon and C\u00f4te d\u2019Ivoire were presented on a net basis. This change has been implemented to more accurately represent the Group\u2019s income tax obligations in Gabon and C\u00f4te d\u2019Ivoire and to be more comparable with other entities in the sector. Prior period balances have been adjusted to conform with the same presentation. As a result of the change, revenue for the year ended 31 December 2021 increased from $1,273.2 million to $1,285.4 million, whilst income tax expense increased from $283.4 million to $295.5 million. There is no impact on pro\ufb01t/(loss) for the year from continuing activities nor on basic and diluted earnings per share. In addition, the restatement had no impact on reported net assets, cash \ufb02ows or total equity. Accordingly, an additional balance sheet as at 1 January 2020 has not been presented. Refer to Note 6. Other than the above, the Group\u2019s accounting policies are consistent with the prior year. ",
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"fact-350": {
"value": "(d) Basis of preparation The Financial Statements have also been prepared in accordance with UK-adopted international accounting standards (UK-adopted IFRSs) and International Financial Reporting Standards adopted pursuant to Regulation (EC) No. 1606/2002 as it applies in the European Union. The \ufb01nancial reporting framework that has been applied in the preparation of the parent company \ufb01nancial statements is applicable law and United Kingdom Accounting Standards, including FRS 101 \u201cReduced Disclosure Framework\u201d (United Kingdom Generally Accepted Accounting Practice). The Financial Statements have been prepared on the historical cost basis, except for derivative \ufb01nancial instruments and contingent consideration which have been measured at fair value which are carried at fair value less cost to sell. The Financial Statements are presented in US dollars and all values are rounded to the nearest $0.1 million, except where otherwise stated. The principal accounting policies adopted by the Group are set out below. Liquidity risk management and going concern Assessment period and assumptions The Directors consider the going concern assessment period to be up to 31 March 2024. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets and different outcomes on ongoing disputes or litigation. Management has applied the following oil price assumptions for the going concern assessment: Base Case: $84/bbl for 2023, $79/bbl for 2024; and Low Case: $70/bbl for 2023, $70/bbl for 2024. The Low Case includes, amongst other downside assumptions, a 5% production decrease compared to the Base Case. (d) Basis of preparation continued Liquidity risk management and going concern continued At 31 December 2022, the Group had $1.1 billion liquidity headroom consisting of c.$0.6 billion free cash and $0.5 billion available under the revolving credit facility. The Group\u2019s forecasts show that the Group will be able to operate within its current debt facilities and have sufficient \ufb01nancial headroom for the going concern assessment period under its Base Case and Low Case. Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Thus, they have adopted the going concern basis of accounting in preparing the year end result. ",
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},
"fact-426": {
"value": "Liquidity risk management and going concern Assessment period and assumptions The Directors consider the going concern assessment period to be up to 31 March 2024. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets and different outcomes on ongoing disputes or litigation. Management has applied the following oil price assumptions for the going concern assessment: Base Case: $84/bbl for 2023, $79/bbl for 2024; and Low Case: $70/bbl for 2023, $70/bbl for 2024. The Low Case includes, amongst other downside assumptions, a 5% production decrease compared to the Base Case. Liquidity risk management and going concern continued At 31 December 2022, the Group had $1.1 billion liquidity headroom consisting of c.$0.6 billion free cash and $0.5 billion available under the revolving credit facility. The Group\u2019s forecasts show that the Group will be able to operate within its current debt facilities and have sufficient \ufb01nancial headroom for the going concern assessment period under its Base Case and Low Case. Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Thus, they have adopted the going concern basis of accounting in preparing the year end result. Liquidity risk The Group manages its liquidity risk using both short-term and long-term cash \ufb02ow projections, supplemented by debt \ufb01nancing plans and active portfolio management across the Group. Ultimate responsibility for liquidity risk management rests with the Board of Directors, which has established an appropriate liquidity risk management framework covering the Group\u2019s short, medium and long-term funding and liquidity management requirements. The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets and delays to development projects. The Group had $1.1 billion (2021: $0.9 billion) of total facility headroom and free cash as at 31 December 2022. The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative \ufb01nancial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash \ufb02ows of \ufb01nancial liabilities based on the earliest date on which the Group can be required to pay. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-410": {
"value": "Liquidity risk management and going concern Assessment period and assumptions The Directors consider the going concern assessment period to be up to 31 March 2024. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets and different outcomes on ongoing disputes or litigation. Management has applied the following oil price assumptions for the going concern assessment: Base Case: $84/bbl for 2023, $79/bbl for 2024; and Low Case: $70/bbl for 2023, $70/bbl for 2024. The Low Case includes, amongst other downside assumptions, a 5% production decrease compared to the Base Case. Liquidity risk management and going concern continued At 31 December 2022, the Group had $1.1 billion liquidity headroom consisting of c.$0.6 billion free cash and $0.5 billion available under the revolving credit facility. The Group\u2019s forecasts show that the Group will be able to operate within its current debt facilities and have sufficient \ufb01nancial headroom for the going concern assessment period under its Base Case and Low Case. Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Thus, they have adopted the going concern basis of accounting in preparing the year end result. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoingConcernExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-351": {
"value": "(e) Basis of consolidation The consolidated Financial Statements incorporate the Financial Statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power over an investee entity, is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to use its power to affect its returns. The results of subsidiaries acquired or disposed of during the year are included in the Group income statement from the transaction date of acquisition, being the date on which the Group gains control, and will continue to be included until the date that control ceases. If the Group loses control over a subsidiary, it derecognises the related assets, liabilities, non-controlling interest and other components of equity, while any resultant gain or loss is recognised in pro\ufb01t or loss. Any investment retained is recognised at fair value. All intra-Group transactions, balances, income and expenses are eliminated on consolidation. Where necessary, adjustments are made to the Financial Statements of subsidiaries to bring the accounting policies used into line with those used by the Group. Joint arrangements The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classi\ufb01ed as joint operations in accordance with IFRS 11. The Group accounts for its share of the results and assets and liabilities of these joint operations. In addition, where Tullow acts as operator to the joint operation, the gross liabilities and receivables (including amounts due to or from non-operating partners) of the joint operation are included in the Group\u2019s balance sheet. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-352": {
"value": "(f) Business combinations The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other assets are acquired. The consideration transferred for the acquisition comprises of: - Fair values of the assets transferred; - Liabilities incurred to the former owners of the acquired business; - Equity interests issued by the group; - Fair value of any asset or liability resulting from a contingent consideration arrangement; and - Fair value of any pre-existing equity interest in the subsidiary. The Group determines that it has acquired a business when the acquired set of activities and assets include an input and a substantive process that together signi\ufb01cantly contribute to the ability to create outputs. The acquired process is considered substantive if it is critical to the ability to continue producing outputs, and the inputs acquired include an organised workforce with the necessary skills, knowledge, or experience to perform that process or it signi\ufb01cantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without signi\ufb01cant cost, effort, or delay in the ability to continue producing outputs. Identi\ufb01able assets acquired and liabilities and contingent liabilities assumed when control is obtained over a business, and when an interest or an additional interest is acquired in a joint operation which is a business are, with limited exceptions, measured initially at their fair values at the acquisition date. Acquisition-related costs are expensed as incurred. The excess of the consideration transferred, amount of any non-controlling interest in the acquired entity, and acquisition-date fair value of any previous equity interest in the acquired entity over the fair value of the net identi\ufb01able assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net identi\ufb01able assets of the business acquired, the difference is recognised directly in pro\ufb01t or loss as a bargain purchase. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-353": {
"value": "(g) Revenue from contracts with customers Revenue from contracts with customers represents the sales value, net of VAT, of the Group\u2019s share of liftings in the year. Revenue is recognised when control of the goods or services are transferred to the customer at an amount that re\ufb02ects the consideration to which the Group expects to be entitled in exchange for those goods or services. The Group has concluded that it is the principal in all of its revenue arrangements since it controls the goods or services before transferring them to the customer. The crude oil produced by the upstream operations is sold to external customers. Revenue from the sale of crude oil is recognised at the point in time when control of the product is transferred to the customer, which is typically when goods are delivered, and title has passed. The transportation and shipping costs associated with the transfer of the product to the point of sale is recognised as a selling cost. Under the terms of the relevant production sharing arrangements, the Group is entitled to its participating share in the crude oil based on the Group\u2019s working interest. Revenue from contracts with customers is recognised based on the actual volumes sold to customers. No adjustments are made to revenue for any differences between volumes sold to customers and unsold volumes which the Group is entitled to sell based on its working interest. Revenue in respect of such volumes is only recognised when there is a transfer of output to the Group\u2019s customers. Differences between the volume which the Group is entitled to sell based on its working interest and the actual volumes that the Group has sold to customers are recognised as an under/overlift (note (g)) within cost of sales. Under the terms of the Production Sharing Contracts in Gabon and C\u00f4te d\u2019Ivoire, the Group is not required to pay any corporate income taxes. The share of the pro\ufb01t oil which the government is entitled to is deemed to include a portion representing the notional corporate income tax paid by the government on behalf of the contractors. This portion of notional corporate income tax is presented as an income tax expenses with a corresponding amount recognised in Revenue. The Group\u2019s sales of crude oil are priced based on the consideration speci\ufb01ed in contracts with customers with reference to quoted market prices in active markets, adjusted for a quality differential based on gravity of the crude oil sold relative to Brent. Invoices are typically paid on 30-60 day terms. For certain non-operated arrangements, the Group\u2019s stake is structured as a carried interest, in which all costs relating to the performance of petroleum operations are borne by the operator and other joint venture partners and are recovered upon production. The recognition of revenue is on net basis, where the Group only accounts for its share of pro\ufb01t oil. ",
"dimensions": {
"concept": "tullowoilplc:DescriptionOfAccountingPolicyForRevenueFromContractsWithCustomers",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-354": {
"value": "(h) Over/underlift Lifting or offtake arrangements for oil and gas produced in certain of the Group\u2019s jointly owned operations are such that each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative production less stock is underlift or overlift. Underlift and overlift are valued at market value and included within receivables and payables respectively. Movements during an accounting period are adjusted through cost of sales such that gross pro\ufb01t is recognised on an entitlements basis. ",
"dimensions": {
"concept": "tullowoilplc:DescriptionOfAccountingPolicyForOverUnderlift",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-355": {
"value": "(i) Inventories Inventories, other than oil products, are stated at the lower of cost and net realisable value. Cost is determined on a weighted average cost basis and comprises direct purchase costs. Net realisable value is determined by reference to prices existing at the balance sheet date, less estimated costs of completion and the estimated costs necessary to make the sale. Oil product is stated at net realisable value and changes in net realisable value are recognised in the income statement. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-411": {
"value": "(j) Foreign currencies The US dollar is the presentational currency of the Group. For the purpose of presenting consolidated \ufb01nancial statements, the assets and liabilities of the Group\u2019s non-US dollar-denominated entities are translated at exchange rates prevailing on the balance sheet date. Income and expense items are translated at the average exchange rate for the period. Currency translation adjustments arising on the restatement of opening net assets of non-US dollar subsidiaries, together with differences between the subsidiaries\u2019 results translated at average rates versus closing rates, are recognised in the statement of comprehensive income and expense and transferred to the foreign currency translation reserve. All resulting exchange differences are classi\ufb01ed as equity until disposal of the subsidiary. On disposal, the cumulative amounts of the exchange differences are recognised as income or expense. Transactions in foreign currencies are recorded at the rates of exchange ruling at the transaction dates. Monetary assets and liabilities are translated into functional currency at the exchange rate ruling at the balance sheet date, with a corresponding charge or credit to the income statement. However, exchange gains and losses arising on monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign operation, are recognised in the foreign currency translation reserve and recognised in pro\ufb01t or loss on disposal of the net investment. In addition, exchange gains and losses arising on long-term foreign currency borrowings which are a hedge against the Group\u2019s overseas investments are dealt with in reserves. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-356": {
"value": "(j) Foreign currencies The US dollar is the presentational currency of the Group. For the purpose of presenting consolidated \ufb01nancial statements, the assets and liabilities of the Group\u2019s non-US dollar-denominated entities are translated at exchange rates prevailing on the balance sheet date. Income and expense items are translated at the average exchange rate for the period. Currency translation adjustments arising on the restatement of opening net assets of non-US dollar subsidiaries, together with differences between the subsidiaries\u2019 results translated at average rates versus closing rates, are recognised in the statement of comprehensive income and expense and transferred to the foreign currency translation reserve. All resulting exchange differences are classi\ufb01ed as equity until disposal of the subsidiary. On disposal, the cumulative amounts of the exchange differences are recognised as income or expense. Transactions in foreign currencies are recorded at the rates of exchange ruling at the transaction dates. Monetary assets and liabilities are translated into functional currency at the exchange rate ruling at the balance sheet date, with a corresponding charge or credit to the income statement. However, exchange gains and losses arising on monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign operation, are recognised in the foreign currency translation reserve and recognised in pro\ufb01t or loss on disposal of the net investment. In addition, exchange gains and losses arising on long-term foreign currency borrowings which are a hedge against the Group\u2019s overseas investments are dealt with in reserves. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-357": {
"value": "(k) Intangible, exploration and evaluation assets and oil and gas assets The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Pre-licence costs are expensed in the period in which they are incurred. All licence acquisition, exploration and evaluation costs and directly attributable administration costs are initially capitalised in cost centres by well, \ufb01eld or exploration area, as appropriate. These costs are then written off as exploration costs in the income statement unless commercial reserves have been established or the determination process has not been completed and there are no indications of impairment. Exploration and evaluation assets are tested for impairment when reclassi\ufb01ed to development assets, or whenever facts and circumstances indicate impairment. An impairment loss is recognised for the amounts by which the exploration and evaluation assets\u2019 carrying amount exceeds their recoverable amount. The recoverable amount is the higher of the exploration and evaluation asset\u2019s fair value less cost to sell and their value in use. Once commercial reserves are found, exploration and evaluation assets are tested for impairment and transferred to development assets. No depreciation and/or amortisation is charged during the exploration and evaluation phase. All \ufb01eld development costs are capitalised as property, plant and equipment. Property, plant and equipment related to production activities is amortised in accordance with the Group\u2019s depletion and amortisation accounting policy. Cash consideration received on farm-down of exploration and evaluation assets is credited against the carrying value of the asset. The excess amount over the carrying value of the asset is recognised as a gain on disposal of exploration and evaluation assets in the statement of pro\ufb01t or loss. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-358": {
"value": "(l) Commercial reserves Commercial reserves are proven and probable oil and gas reserves, which are de\ufb01ned as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a speci\ufb01ed degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and probable reserves and a 50% statistical probability that it will be less. ",
"dimensions": {
"concept": "tullowoilplc:DescriptionOfCommercialReserves",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-359": {
"value": "(m) Depletion and amortisation All expenditure carried within each \ufb01eld is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a \ufb01eld-by-\ufb01eld basis or by a group of \ufb01elds which are reliant on common infrastructure. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future \ufb01eld development costs required to recover the commercial reserves remaining. Changes in the estimates of commercial reserves or future \ufb01eld development costs are dealt with prospectively. ",
"dimensions": {
"concept": "tullowoilplc:DescriptionOfAccountingPolicyForDepletionAndAmortisation",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-360": {
"value": "(n) Impairment of property, plant and equipment The Group assesses at each reporting date whether there is an indication that an asset (or CGU) may be impaired. In assessing whether an impairment is required, the carrying value of the asset or CGU is compared with its recoverable amount. The recoverable amount is the higher of the asset\u2019s/CGU\u2019s fair value less costs of disposal (FVLCD) and value in use (VIU). Given the nature of the Group\u2019s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers or similar transactions are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment charges described below is VIU. The Group estimates VIU using a discounted cash \ufb02ow model. In order to discount the future cash \ufb02ows the Group calculates asset or CGU-speci\ufb01c discount rates. The discount rates are based on an assessment of a relevant peer group\u2019s post-tax weighted average cost of capital (WACC). The post-tax WACC is subsequently grossed up to a pre-tax rate. The Group then deducts any exploration risk premium which is implicit within a peer group\u2019s WACC and subsequently applies additional country risk premium for all CGUs, an element of which is determined by whether the assets are onshore or offshore. Where there is evidence of economic interdependency between \ufb01elds, such as common infrastructure, the \ufb01elds are grouped as a single CGU for impairment purposes. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the income statement, net of any amortisation that would have been charged since the impairment. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-361": {
"value": "(o) Decommissioning Provision for decommissioning is recognised in full when the related facilities are installed. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of decommissioning, discounted to its net present value using a risk-free rate, and is re-assessed each year in accordance with local conditions and requirements. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. The unwinding of the discount on the decommissioning provision is included as a \ufb01nance cost. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-362": {
"value": "(p) Property, plant and equipment \u2013 non-oil and gas assets Property, plant and equipment is stated in the balance sheet at cost less accumulated depreciation and any recognised impairment loss. Depreciation on property, plant and equipment other than production assets is provided at rates calculated to write off the cost less the estimated residual value of each asset on a straight-line basis over its expected useful economic life of between three and ten years. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-363": {
"value": "(q) Borrowing costs Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale. All other \ufb01nance costs, which include interest on borrowings calculated using the effective interest method as described in paragraph (aa), obligations under \ufb01nance leases, the unwinding effect of discounting provisions and exchange differences, are recognised in the income statement in the period in which they are incurred. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-364": {
"value": "(r) Share issue expenses and share premium account Costs of share issues are written off against the premium arising on the issues of share capital. ",
"dimensions": {
"concept": "tullowoilplc:DescriptionOfAccountingPolicyForShareIssueAndSharePremiumAccount",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-412": {
"value": "(s) Taxation Current and deferred tax, including UK corporation tax and overseas corporation tax, are provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred corporation tax is recognised on all temporary differences that have originated but not reversed at the balance sheet date where transactions or events that result in an obligation to pay more, or right to pay less, tax in the future have occurred at the balance sheet date. Deferred tax assets are recognised only to the extent that it is considered more likely than not that there will be suitable taxable pro\ufb01ts from which the underlying temporary differences can be deducted. Deferred tax is measured on a non-discounted basis. Deferred tax is provided on temporary differences arising on acquisitions that are categorised as business combinations. Deferred tax is recognised at acquisition as part of the assessment of the fair value of assets and liabilities acquired. Any deferred tax is charged or credited in the income statement as the underlying temporary difference is reversed. Petroleum revenue tax (PRT) is treated as an income tax and deferred PRT is accounted for under the temporary difference method. UK PRT refunds are included in the income statement and is taxable for UK corporation tax. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-365": {
"value": "(s) Taxation Current and deferred tax, including UK corporation tax and overseas corporation tax, are provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred corporation tax is recognised on all temporary differences that have originated but not reversed at the balance sheet date where transactions or events that result in an obligation to pay more, or right to pay less, tax in the future have occurred at the balance sheet date. Deferred tax assets are recognised only to the extent that it is considered more likely than not that there will be suitable taxable pro\ufb01ts from which the underlying temporary differences can be deducted. Deferred tax is measured on a non-discounted basis. Deferred tax is provided on temporary differences arising on acquisitions that are categorised as business combinations. Deferred tax is recognised at acquisition as part of the assessment of the fair value of assets and liabilities acquired. Any deferred tax is charged or credited in the income statement as the underlying temporary difference is reversed. Petroleum revenue tax (PRT) is treated as an income tax and deferred PRT is accounted for under the temporary difference method. UK PRT refunds are included in the income statement and is taxable for UK corporation tax. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-367": {
"value": "(t) Pensions Contributions to the Group\u2019s de\ufb01ned contribution pension schemes are charged to operating pro\ufb01t on an accrual basis. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-366": {
"value": "(u) Derivative \ufb01nancial instruments The Group uses derivative \ufb01nancial instruments, such as forward currency contracts and commodity options contracts, to hedge its foreign currency risks and commodity price risks respectively. Derivatives are recognised initially at fair value at the date a derivative contract is entered into and are subsequently remeasured to their fair value at each reporting date. The resulting gain or loss is recognised in pro\ufb01t or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in pro\ufb01t or loss depends on the nature of the hedge relationship. For the purpose of hedge accounting, hedges are classi\ufb01ed as: - fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability or an unrecognised \ufb01rm commitment; - cash \ufb02ow hedges when hedging the exposure to variability in cash \ufb02ows that is either attributable to a particular risk; - associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an unrecognised \ufb01rm commitment; and - hedges of a net investment in a foreign operation. At the inception of a hedge relationship, the Group formally designates and documents the hedge relationship to which it wishes to apply hedge accounting. (u) Derivative \ufb01nancial instruments continued The documentation includes identi\ufb01cation of the hedging instrument, the hedged item, the nature of the risk being hedged and how the Group will assess whether the hedging relationship meets the hedge effectiveness requirements (including the analysis of sources of hedge ineffectiveness and how the hedge ratio is determined). A hedging relationship quali\ufb01es for hedge accounting if it meets all of the following effectiveness requirements: - There is \u2018an economic relationship\u2019 between the hedged item and the hedging instrument; - The effect of credit risk does not \u2018dominate the value changes\u2019 that result from that economic relationship; and - The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the time value hedge reserve. If the hedged item is transaction related, the time value is reclassi\ufb01ed to pro\ufb01t or loss when the hedged item affects pro\ufb01t or loss. If the hedged item is time-period related, then the amount accumulated in the time value hedge reserve is reclassi\ufb01ed to pro\ufb01t or loss on a rational basis. Those reclassi\ufb01ed amounts are recognised in pro\ufb01t or loss in the same line as the hedged item. Furthermore, if the Group expects that some or all of the loss accumulated in hedging reserve will not be recovered in the future, that amount is immediately reclassi\ufb01ed to pro\ufb01t or loss. Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the \ufb01nancial asset to that asset\u2019s net carrying amount. Cash \ufb02ow hedges The effective portion of the gain or loss on the hedging instrument is recognised in OCI in the cash \ufb02ow hedge reserve, while any ineffective portion is recognised immediately in the statement of pro\ufb01t or loss. The cash \ufb02ow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. The Group uses oil option contracts for its exposure to volatility of Dated Brent prices. The ineffective portion relating to option contracts is recognised as gain or loss on hedging instruments in the Group income statement. Amounts previously recognised in other comprehensive income and accumulated in equity are reclassi\ufb01ed to pro\ufb01t or loss in the periods when the hedged item affects pro\ufb01t or loss, in the same line as the recognised hedged item. Cash \ufb02ow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the hedging instrument is sold, terminated or exercised without replacement or rollover. When cash \ufb02ow hedge accounting is discontinued, amounts previously recognised within other comprehensive income remain in equity until the forecast transaction occurs and are reclassi\ufb01ed to pro\ufb01t or loss or transferred to the initial carrying amount of a non-\ufb01nancial asset or liability as above. If the forecast transaction is no longer expected to occur, amounts previously recognised within other comprehensive income will be immediately reclassi\ufb01ed to pro\ufb01t or loss. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-413": {
"value": "(u) Derivative \ufb01nancial instruments The Group uses derivative \ufb01nancial instruments, such as forward currency contracts and commodity options contracts, to hedge its foreign currency risks and commodity price risks respectively. Derivatives are recognised initially at fair value at the date a derivative contract is entered into and are subsequently remeasured to their fair value at each reporting date. The resulting gain or loss is recognised in pro\ufb01t or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in pro\ufb01t or loss depends on the nature of the hedge relationship. For the purpose of hedge accounting, hedges are classi\ufb01ed as: - fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability or an unrecognised \ufb01rm commitment; - cash \ufb02ow hedges when hedging the exposure to variability in cash \ufb02ows that is either attributable to a particular risk; - associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an unrecognised \ufb01rm commitment; and - hedges of a net investment in a foreign operation. At the inception of a hedge relationship, the Group formally designates and documents the hedge relationship to which it wishes to apply hedge accounting. (u) Derivative \ufb01nancial instruments continued The documentation includes identi\ufb01cation of the hedging instrument, the hedged item, the nature of the risk being hedged and how the Group will assess whether the hedging relationship meets the hedge effectiveness requirements (including the analysis of sources of hedge ineffectiveness and how the hedge ratio is determined). A hedging relationship quali\ufb01es for hedge accounting if it meets all of the following effectiveness requirements: - There is \u2018an economic relationship\u2019 between the hedged item and the hedging instrument; - The effect of credit risk does not \u2018dominate the value changes\u2019 that result from that economic relationship; and - The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the time value hedge reserve. If the hedged item is transaction related, the time value is reclassi\ufb01ed to pro\ufb01t or loss when the hedged item affects pro\ufb01t or loss. If the hedged item is time-period related, then the amount accumulated in the time value hedge reserve is reclassi\ufb01ed to pro\ufb01t or loss on a rational basis. Those reclassi\ufb01ed amounts are recognised in pro\ufb01t or loss in the same line as the hedged item. Furthermore, if the Group expects that some or all of the loss accumulated in hedging reserve will not be recovered in the future, that amount is immediately reclassi\ufb01ed to pro\ufb01t or loss. Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the \ufb01nancial asset to that asset\u2019s net carrying amount. Cash \ufb02ow hedges The effective portion of the gain or loss on the hedging instrument is recognised in OCI in the cash \ufb02ow hedge reserve, while any ineffective portion is recognised immediately in the statement of pro\ufb01t or loss. The cash \ufb02ow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. The Group uses oil option contracts for its exposure to volatility of Dated Brent prices. The ineffective portion relating to option contracts is recognised as gain or loss on hedging instruments in the Group income statement. Amounts previously recognised in other comprehensive income and accumulated in equity are reclassi\ufb01ed to pro\ufb01t or loss in the periods when the hedged item affects pro\ufb01t or loss, in the same line as the recognised hedged item. Cash \ufb02ow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the hedging instrument is sold, terminated or exercised without replacement or rollover. When cash \ufb02ow hedge accounting is discontinued, amounts previously recognised within other comprehensive income remain in equity until the forecast transaction occurs and are reclassi\ufb01ed to pro\ufb01t or loss or transferred to the initial carrying amount of a non-\ufb01nancial asset or liability as above. If the forecast transaction is no longer expected to occur, amounts previously recognised within other comprehensive income will be immediately reclassi\ufb01ed to pro\ufb01t or loss. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-368": {
"value": "(v) Convertible bonds Where bonds issued with certain conversion rights are identi\ufb01ed as compound instruments, the liability and equity components are separately recognised. The fair value of the liability component on initial recognition is calculated by discounting the contractual stream of future cash \ufb02ows using the prevailing market interest rate for similar non-convertible debt. The difference between the fair value of the liability component and the fair value of the whole instrument is recorded as equity. Transaction costs are apportioned between the liability and the equity components of the instrument based on the amounts initially recognised. The liability component is subsequently measured at amortised cost using the effective interest rate method, in line with our other \ufb01nancial liabilities. The equity component is not remeasured. On conversion of the instrument, equity is issued and the liability component is derecognised. The original equity component recognised at inception remains in equity. No gain or loss is recognised on conversion. In an event of a repayment of the liability component, the original equity component is transferred to retained earnings. ",
"dimensions": {
"concept": "tullowoilplc:DescriptionOfAccountingPolicyForConvertibleBonds",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-369": {
"value": "(w) Leases On inception of a contract, the Group assesses whether the contract is, or contains, a lease. The contract is, or contains, a lease if it conveys the right to control the use of an identi\ufb01ed asset for a period of time in exchange for consideration. To determine whether the contract conveys the right to control the use of an identi\ufb01ed asset, the Group assesses whether the contract involves the use of an identi\ufb01ed asset, the Group has the right to obtain substantially all of the economic bene\ufb01ts from the use of the asset throughout the period of use, and the Group has the right to direct the use of the asset. i) Lessee accounting Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability, in case of Joint operation, adjusted for any amount receivable from Joint Venture Partners and any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs required to remove or restore the underlying asset, less any lease incentives received. The right-of-use asset is depreciated over the shorter of the asset\u2019s useful life and the lease term on a straight-line basis, or applying the unit of production method, and the Joint Venture receivable is allocated against the monthly Joint Venture billing cycle. The initial measurement of the corresponding lease liability is at the present value of the lease payments that are not paid at the lease commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Group\u2019s incremental borrowing rate. The lease payments include \ufb01xed payments, less any lease incentive receivable, variable leases payments based on an index or rate, and amounts expected to be payable by the lessee under residual value guarantees. The lease liability is subsequently measured at amortised cost using the effective interest method. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the Group\u2019s estimate of the amount expected to be payable under a residual value guarantee or if the Group changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset or is recorded in pro\ufb01t or loss if the carrying amount of the right-of-use asset has been reduced to zero. The Group has elected not to recognise right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less, and leases of low-value assets with a value of $5,000. Over the course of a lease contract, there will be taxable timing differences that could give rise to deferred tax, subject to local tax laws and regulations. Extension and termination options are included in a number of property and equipment leases across the Group. These are used to maximise operational \ufb02exibility in terms of managing the assets used in the Group\u2019s operations. The majority of extension and termination options held are exercisable only by the Group and not by the respective lessor. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-370": {
"value": "(x) Share-based payments The Group has applied the requirements of IFRS 2 Share-based Payments. The Group has share-based awards that are equity settled and cash settled as de\ufb01ned by IFRS 2. The fair value of the equity settled awards has been determined at the date of grant of the award allowing for the effect of any market-based performance conditions. This fair value, adjusted by the Group\u2019s estimate of the number of awards that will eventually vest as a result of non-market conditions, is expensed uniformly over the vesting period. The fair values were calculated using a binomial option pricing model with suitable modi\ufb01cations to allow for employee turnover after vesting and early exercise. Where necessary, this model is supplemented with a Monte Carlo model. The inputs to the models include: the share price at date of grant; exercise price; expected volatility; expected dividends; risk-free rate of interest; and patterns of exercise of the plan participants. For cash settled awards, a liability is recognised for the goods or service acquired, measured initially at the fair value of the liability. At each balance sheet date until the liability is settled, and at the date of settlement, the fair value of the liability is remeasured, with any changes in fair value recognised in the income statement. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-371": {
"value": "(y) Financial assets At initial recognition, the Group measures a \ufb01nancial asset at its fair value plus, in the case of a \ufb01nancial asset not at fair value through pro\ufb01t or loss (FVPL), transaction costs that are directly attributable to the acquisition of the \ufb01nancial asset. Transaction costs of \ufb01nancial assets carried at FVPL are expensed in pro\ufb01t or loss. The subsequent measurement of \ufb01nancial assets depends on their classi\ufb01cation, as set out overleaf. i) Financial assets measured at amortised cost Assets are subsequently classi\ufb01ed and measured at amortised cost when the business model of the Company is to collect contractual cash \ufb02ows and the contractual terms give rise to cash \ufb02ows that are solely payments of principal and interest. These assets are carried at amortised cost using the effective interest method if the time value of money is signi\ufb01cant. Gains and losses are recognised in pro\ufb01t or loss when the assets are derecognised, modi\ufb01ed or impaired. This category of \ufb01nancial assets includes trade and other receivables. Financial assets measured at amortised cost include trade receivables, loans and other receivables that have \ufb01xed or determinable payments that are not quoted in an active market. Loans and receivables are measured at amortised cost using the effective interest method, less any impairment. Interest income is recognised by applying the effective interest rate, except for short-term receivables when the recognition of interest would be immaterial. ii) Financial asset measured at fair value through other comprehensive income Assets are subsequently classi\ufb01ed and measured at fair value through other comprehensive income when the business model of the Company is to collect contractual cash \ufb02ows and sell the \ufb01nancial assets, and the contractual cash \ufb02ows represent solely payments of principal and interest. iii) Financial assets measured at fair value through pro\ufb01t or loss Financial assets are classi\ufb01ed as measured at fair value through pro\ufb01t or loss when the asset does not meet the criteria to be measured at amortised cost or fair value through other comprehensive income. These assets are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category. As at 31 December 2022, the Group does not have any \ufb01nancial assets classi\ufb01ed at fair value through pro\ufb01t or loss or other comprehensive income. Regular way purchases and sales of \ufb01nancial assets are recognised on trade date, being the date on which the Group commits to purchase or sell the asset. Financial assets are derecognised when the rights to receive cash \ufb02ows from the \ufb01nancial assets have expired or have been transferred and the Group has transferred substantially all the risks and rewards of ownership. Impairment of trade and joint venture receivables The Group applies the IFRS 9 simpli\ufb01ed approach to measuring expected credit losses which uses a lifetime expected loss allowance for all trade receivables. To measure the expected credit losses, trade receivables have been grouped based on shared credit risk characteristics and days past due. The expected loss rates are based on the payment pro\ufb01les of sales over the historical period and the corresponding historical credit losses experienced within this period. These rates are then applied to the gross carrying amount of the receivable to arrive at the loss allowance for the period. Based on Management assessment the credit loss in trade receivables and joint venture receivable as at 31 December 2022 would be immaterial; therefore, in line with IFRS 9, no impairment was recognised (2021: $nil). In order to minimise the risk of default, credit risk is managed on a Group basis (note 18). ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-372": {
"value": "(z) Cash and cash equivalents Cash and cash equivalents comprise cash at bank, demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insigni\ufb01cant risk of changes in value. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-373": {
"value": "(aa) Effective interest method The effective interest method is a method of calculating the amortised cost of a \ufb01nancial asset and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees on points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the \ufb01nancial asset, or, where appropriate, a shorter period. Income is recognised on an effective interest basis for debt instruments other than those \ufb01nancial assets classi\ufb01ed as at FVTPL. ",
"dimensions": {
"concept": "tullowoilplc:DescriptionOfAccountingPolicyForEffectiveInterestMethod",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-374": {
"value": "(ab) Financial liabilities The measurement of \ufb01nancial liabilities is determined by the initial classi\ufb01cation. i) Financial liabilities at fair value through pro\ufb01t or loss: Those balances that meet the de\ufb01nition of being held for trading are measured at fair value through pro\ufb01t or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognised in the income statement. ii) Financial liabilities measured at amortised cost: All \ufb01nancial liabilities not meeting the criteria of being classi\ufb01ed at fair value through pro\ufb01t or loss are classi\ufb01ed as \ufb01nancial liabilities measured at amortised cost. The instruments are initially recognised at its fair value net of transaction costs that are directly attributable to the issue of \ufb01nancial liability. Subsequent to initial recognition, \ufb01nancial liabilities are measured at amortised cost using the effective interest method. Trade payables and borrowings fall under this category of \ufb01nancial instruments. As at 31 December 2022 all \ufb01nancial liabilities are measured at amortised cost. The Group derecognises a \ufb01nancial liability when it is extinguished, i.e. when the obligation speci\ufb01ed in the contract is discharged or cancelled or expires. A substantial modi\ufb01cation of the terms of an existing \ufb01nancial liability or a part of it is accounted for as an extinguishment of the original \ufb01nancial liability and the recognition of a new \ufb01nancial liability. Offsetting of \ufb01nancial instruments: Financial assets and \ufb01nancial liabilities are offset and the net amount is reported in the consolidated statement of \ufb01nancial position if there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis, to realise the assets and settle the liabilities simultaneously. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-375": {
"value": "(ac) Equity instruments Equity instruments are classi\ufb01ed according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities. Equity instruments issued by the Group are recorded at the proceeds received, net of direct issue costs. ",
"dimensions": {
"concept": "tullowoilplc:DescriptionOfAccountingPolicyForEquityInstruments",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-376": {
"value": "(ad) Insurance proceeds Insurance proceeds related to lost production under the Business Interruption insurance policy are recorded as other operating income in the income statement. Proceeds related to compensation for incremental operating costs under the Business Interruption and Hull and Machinery insurance policies are recorded within the operating costs line of cost of sales. Proceeds related to compensation for capital costs under insurance policies are recorded within pro\ufb01t and loss with corresponding cost for replacement asset as additions to property, plant and equipment. Insurance proceeds are recognised at the point when the realisation of income is virtually certain. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForInsuranceContracts",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-377": {
"value": "(ae) Provisions Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an out\ufb02ow of resources embodying economic bene\ufb01ts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Onerous contracts If the Group has a contract that is onerous, the present obligation under the contract is recognised and measured as a provision. However, before a separate provision for an onerous contract is established, the Group recognises any impairment loss that has occurred on assets dedicated to that contract. An onerous contract is a contract under which the unavoidable costs (i.e., the costs that the Group cannot avoid because it has the contract) of meeting the obligations under the contract exceed the economic bene\ufb01ts expected to be received under it. The unavoidable costs under a contract re\ufb02ect the least net cost of exiting from the contract, which is the lower of the cost of ful\ufb01lling it and any compensation or penalties arising from failure to ful\ufb01l it. The cost of ful\ufb01lling a contract comprises the costs that relate directly to the contract (i.e., both incremental costs and an allocation of costs directly related to contract activities). ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-378": {
"value": "(af) Critical accounting judgements The Group assesses critical accounting judgements annually. The following are the critical judgements, apart from those involving estimations which are dealt with in policy (ag), that the Directors have made in the process of applying the Group\u2019s accounting policies and that have the most signi\ufb01cant effect on the amounts recognised in the Financial Statements. Carrying value of intangible exploration and evaluation assets (note 9) The amounts for intangible exploration and evaluation assets represent active exploration projects. These amounts will be written off to the income statement as exploration costs unless commercial reserves are established or the determination process is not completed and there are no indications of impairment in accordance with the Group\u2019s accounting policy. The process of determining whether there is an indicator for impairment or calculating the impairment requires critical judgement. The key areas in which Management has applied judgement and estimation are as follows: the Group\u2019s intention to proceed with a future work programme for a prospect or licence; the likelihood of licence renewal or extension; the assessment of whether sufficient data exist to indicate that, although a development in the speci\ufb01c area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale; and the success of a well result or geological or geophysical survey. Details on impact of these key estimates using sensitivities applied to impairment models can be found in note 9. The most material area where judgement was applied during 2022 was in the assessment of the value in use (VIU) of the Kenyan CGU and assessing the likelihood of recovery of the net book value of the asset. A trigger for potential impairment reversal was identi\ufb01ed following the Group\u2019s increase in long-term oil price assumption resulting in an increase in the underlying value of the project. Due to the stage of this project being pre-\ufb01nal investment decision (FID) and only having 2C resources booked, the VIU assessment required estimation and judgement in a number of different aspects including oil prices differentials, uncontracted cost pro\ufb01les and certain \ufb01scal terms. Furthermore, the Group has identi\ufb01ed the following estimation uncertainties, which require judgement, in respect to the Group\u2019s ability to realise the estimated VIU; receiving an acceptable offer from a strategic partner, obtaining \ufb01nancing for the project and government deliverables. These items require satisfactory resolution before the Group can take FID. Due to the binary nature of these uncertainties the Group was unable to either adjust the cash \ufb02ows or discount rate appropriately. It has therefore used its judgement and assessed the probability of achieving FID and therefore the recognition of commercial reserves. This probability was applied to the VIU to determine a risk adjusted VIU and compared against the net book value of the asset. Based on this there is no impairment or impairment reversal as at 31 December 2022. Should the uncertainties around the project be resolved there will be a reversal of previously recognised impairment. However, if the uncertainties are not resolved there will be an impairment of $253 million. Lease accounting (note 19) Discount rate The Group has assessed the appropriate incremental borrowing rate applicable for each contract. Management has applied the practical expedient which allows for the adoption of a portfolio approach, where a single discount rate for a portfolio of leases with similar characteristics can be applied. As the Group has external borrowings with a consortium of lenders, these are considered the best reference for the incremental borrowing rate for the Group. The weighted average cost of those borrowings is considered to the Group's 'all in rate', at the lease commencement date if the interest rate implicit in the lease is not readily determinable. As at 31 December 2022, the Group's incremental borrowing rate was 9.82%. Determination of the lease term Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. Extension and termination options are included in a number of property and equipment leases across the Group. These are used to maximise operational \ufb02exibility in terms of managing the assets used in the Group\u2019s operations. For leases relating to Joint Venture operations where there is an option to extend, the Group will only proceed after it has received Joint Venture approval to extend. At the inception of new leases in relation to joint arrangements they do not include any period covered by an extension option in the lease term because they cannot be reasonably certain that approval from the other venturers can be obtained. The majority of extension and termination options held are exercisable only by the Group and not by the respective lessor. Fair valuation of additional interest acquired in Ghana assets (note 15) The additional interest acquired in the Ghana assets has been recorded at fair value as required under IFRS 3. The property, plant and equipment acquired through the business combination has been recognised at the fair value based on the net present value of the discounted future cash \ufb02ows. Signi\ufb01cant inputs to the valuation include short- and long-term commodity prices, reserve estimates, production volume pro\ufb01les, planned development expenditure, cost pro\ufb01les and discount rates, and are consistent with those applied by the management when testing assets for impairments. (ag) Key sources of estimation uncertainty The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a signi\ufb01cant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next \ufb01nancial year, are discussed below. Carrying value of property, plant and equipment (note 10) Management performs impairment reviews on the Group\u2019s property, plant and equipment assets at least annually with reference to indicators in IAS 36 Impairment of Assets. Where indicators of impairments or impairment reversals are present and an impairment or impairment reversal test is required, the calculation of the recoverable amount requires estimation of future cash \ufb02ows within complex impairment models. Key assumptions and estimates in the impairment models relate to: commodity prices assumptions, pre-tax discount rates, commercial reserves and the related cost pro\ufb01les. Proven and probable reserves are estimates of the amount of oil and gas that can be economically extracted from the Group\u2019s oil and gas assets. The Group estimates its reserves using standard recognised evaluation techniques. The estimate is reviewed at least annually by Management and by independent consultants. Proven and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of remaining recoverable reserves and the proportion of the gross reserves which are attributable to host governments under the terms of the Production Sharing Contracts. Future development costs are estimated taking into account the level of development required to produce the reserves by reference to operators, where applicable, and internal engineers. Net entitlement reserves estimates are subsequently calculated using the current oil price and cost recovery assumptions, in line with the relevant agreements. Changes in reserves as a result of factors such as production cost, recovery rates, grade of reserves or oil and gas prices could impact the depletion rates, carrying value of assets (refer to the Commercial Reserves and Contingent Resources Summary on page 176). The estimation applied by Management to the exploration risk premium adjustment to its impairment discount rates, estimated future commodity prices and forecast cash \ufb02ows on the TEN asset would have the most material impact on the 2022 Financial Statements should Management have concluded differently. Details on the impact of these key estimates and judgements using sensitivity applied to impairment models can be found in note 10. Uncertain tax treatments The Group is subject to various material claims which arise in the ordinary course of its business in various jurisdictions, including cost recovery claims, claims from regulatory bodies and both corporate income tax and indirect tax claims. The Group is in formal dispute proceedings regarding a number of these tax claims. The resolution of tax positions, through negotiation with the relevant tax authorities or litigation, can take several years to complete. In assessing whether these claims should be provided for in the Financial Statements, Management has considered them in the context of the applicable laws and relevant contracts for the countries concerned. Management has applied judgement in assessing the likely outcome of the claims and has estimated the \ufb01nancial impact based on external tax and legal advice and prior experience of such claims. Due to the uncertainty of such tax items, it is possible that on conclusion of an open tax matter at a future date the outcome may differ signi\ufb01cantly from Management\u2019s estimate. If the Group was unsuccessful in defending itself from all of these claims, the result would be additional liabilities of $1,024.0 million (2021: $1,025.5 million) which includes $32.4 million of interest and penalties (2021: $33.6 million). Provisions of $106.4 million (2021: $127.9 million) are included in income tax payable ($70.6 million (2021: $34.1 million)), deferred tax liability ($nil (2021:41.0 million)), and provisions ($35.8 million (2021: $52.8 million)). Where these matters relate to expenditure which is capitalised within Intangible Exploration and Evaluation Assets and Property, Plant and Equipment, any difference between the amounts accrued and the amounts settled is capitalised within the relevant asset balance, subject to applicable impairment indicators. Where these matters relate to producing activities or historical issues, any differences between the accrued and settled amounts are taken to the group income statement. The provisions and contingent liabilities relating to these disputes have decreased following the conclusion of tax authority challenges and matters lapsing under the statute of limitations, but have increased, following new claims being initiated and extrapolation of exposures through to 31 December 2022, giving rise to an overall decrease in provision of $21.5 million and decrease in contingent liability of $1.5 million. (ag) Key sources of estimation uncertainty continued Ghana tax assessments In October 2021, Tullow Ghana Limited (TGL) \ufb01led a Request for Arbitration with the International Chamber of Commerce (\u201cICC\u201d) disputing the $320 million branch pro\ufb01ts remittance tax (BPRT) assessment issued as part of the direct tax audit for the \ufb01nancial years 2014 to 2016. The Ghana Revenue Authority (GRA) is seeking to apply BPRT under a law which the Group considers is not applicable to TGL, since it falls outside the tax regime provided for in the Petroleum Agreements and relevant double tax treaties. The parties have agreed a procedural timetable for the arbitration under which the \ufb01rst Tribunal hearing will be held in October 2023. In December 2022, TGL received a $190.5 million corporate income tax assessment and payment demand from the GRA relating to the disallowance of loan interest for the \ufb01nancial years 2010 to 2020. The Group has previously disclosed assessments by the GRA relating to the same issue; this revised assessment supersedes all previous claims. The Group considers the assessment to breach TGL\u2019s rights under its Petroleum Agreements. In February 2023, TGL \ufb01led a Request for Arbitration with the ICC, disputing the assessment with the suspension of TGL\u2019s obligation to pay any amount in relation to the assessment until the dispute is formally resolved. In December 2022, TGL received a $196.5 million corporate income tax assessment and payment demand from the GRA relating to proceeds received by Tullow during the \ufb01nancial years 2016 to 2019 under Tullow\u2019s corporate Business Interruption Insurance policy. The Group considers the assessment to breach TGL\u2019s rights under its Petroleum Agreements. In February 2023, TGL \ufb01led a Request for Arbitration to the ICC, disputing the assessment with the suspension of TGL\u2019s obligation to pay any amount in relation to the assessment until the dispute is formally resolved. The Group continues to engage with the Government of Ghana with the aim of resolving all tax disputes on a mutually acceptable basis. Bangladesh litigation The National Board of Revenue (NBR) is seeking to disallow $118 million of tax relief in respect of development costs incurred by Tullow Bangladesh Limited (TBL). The NBR subsequently issued a payment demand to TBL in February 2020 for Taka 3,094 million (c.$37 million) requesting payment by 15 March 2020. However, under the Production Sharing Contract (PSC), the Government is required to indemnify TBL against all taxes levied by any public authority, and the share of production paid to Petrobangla (PB), Bangladesh\u2019s national oil company, is deemed to include all taxes due which PB is then obliged to pay to the NBR. TBL sent the payment demand to PB and the Government requesting the payment or discharge of the payment demand under their respective PSC indemnities. On 14 June 2021, TBL issued a formal notice of dispute under the PSC to the Government and PB. A further request for payment was received from NBR on 28 October 2021 demanding settlement by 15 November 2021. Arbitration proceedings were initiated under the PSC on 29 December 2021. A procedural hearing was held on 28 June 2022 which set the timetable for the process going forward. The \ufb01rst submissions have been made in October 2022 with the \ufb01rst Tribunal hearing scheduled for May 2024. Other items Other items totalling $280.0 million (2021: 547.5 million) comprise exposures in respect of claims for corporation tax in respect of disallowed expenditure or withholding taxes that are either currently under discussion with the tax authorities or which arise in respect of known issues for periods not yet under audit. Timing of cash \ufb02ows While it is not possible to estimate the timing of tax cash \ufb02ows in relation to possible outcomes with certainty, Management anticipates that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments. ",
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"fact-379": {
"value": "Note 1. Segmental reporting The information reported to the Group\u2019s Chief Executive Officer for the purposes of resource allocation and assessment of segment performance is focused on four Business Units \u2013 Ghana, Non-operated producing assets including Uganda and decommissioning assets, Kenya and Exploration. Therefore, the Group\u2019s reportable segments under IFRS 8 are Ghana, Non-operated, Kenya and Exploration. The following tables present revenue, loss and certain asset and liability information regarding the Group\u2019s reportable business segments for the years ended 31 December 2022 and 31 December 2021. Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m 2022 Sales revenue by origin 1,578.5 524.0 \u2013 \u2013 (319.4) 1,783.1 Segment result1 692.5 337.3 (0.5) (102.6) (337.5) 589.2 Other provisions\u00b2 (4.1) Gain on bargain purchase 196.8 Other gains and losses 3.1 Unallocated corporate expenses\u00b3 (51.1) Operating pro\ufb01t 733.9 Gain on hedging instruments 0.8 Finance income 42.9 Finance costs (335.5) Pro\ufb01t before tax 442.1 Income tax expense (393.0) Pro\ufb01t after tax 49.1 Total assets 3,827.7 380.6 265.6 46.0 519.7 5,039.6 Total liabilities\u2074 (2,220.5) (401.6) (14.1) (4.6) (2,858.3) (5,499.1) Other segment information Capital expenditure: Property, plant and equipment 342.9 26.9 \u2013 \u2013 0.9 370.7 Intangible exploration and evaluation assets 0.9 (1.7) (2.1) 42.1 \u2013 39.2 Depletion, depreciation and amortisation (362.1) (52.7) (1.3) \u2013 (9.7) (425.8) Impairment of property, plant and equipment, net (380.6) (10.6) \u2013 \u2013 \u2013 (391.2) Exploration costs written off (0.9) 1.8 (0.5) (105.6) \u2013 (105.2) 1. Segment result is a non-IFRS measure which includes gross pro\ufb01t, exploration costs written off and impairment of property, plant and equipment. See reconciliation below. 2. This is included within the Restructuring costs and other provisions in the Group Income Statement. 3. Unallocated expenditure include amounts of a corporate nature and not speci\ufb01cally attributable to a geographic area. 4. Total liabilities \u2013 Corporate comprise of the Group\u2019s external debt and other non-attributable liabilities. Reconciliation of segment result 2022 $m 2021 Restated 1 $m Segment result 589.2 532.3 Add back: Exploration costs written off 105.2 59.9 Impairment of property, plant and equipment 391.2 54.3 Gross pro\ufb01t 1,085.6 646.5 1. Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. Refer to note 6. Note 1. Segmental reporting continued All sales are made to external customers. Included in revenue arising from Ghana and Non-Operated segments are revenues of approximately $696.9 million, $566.1 million, $310.9 million and $242.3 million relating to the Group\u2019s customers who each contribute more than 10% of total sales revenue (2021: 329.6 million, $256.9 million, $151.1 million and $145.2 million). As the sales of oil and gas are made on global markets and are highly liquid, the Group does not place reliance on the largest customers mentioned above. Payment terms are typically 30 days from the bill of lading. Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m 2021 Sales revenue by origin \u2013 restated6 1,020.4 417.9 \u2013 \u2013 (152.9) 1,285.4 Segment result1- restated6 469.8 298.7 \u2013 (70.5) (165.7) 532.3 Other provisions\u00b2 6.6 \u2013 (13.2) \u2013 (52.1) (58.7) Gain on disposal 120.3 Unallocated corporate expenses\u00b3 (67.2) Operating pro\ufb01t 526.7 Finance income 44.3 Finance costs (356.1) Pro\ufb01t before tax 214.9 Income tax expense - restated6 (295.6) Loss after tax (80.7) Total assets \u2013 restated6 4,283.8 501.2 264.6 122.3 368.8 5,540.6 Total liabilities\u2074 \u2013 restated 6 (2,529.3) (478.9) (18.0) (12.8) (2,967.7) (6,006.7) Other segment information Capital expenditure: Property, plant and equipment 99.6 43.9 \u2013 \u2013 4.6 148.1 Intangible exploration and evaluation assets\u2075 1.2 (11.8) 8.2 48.8 \u2013 46.3 Depletion, depreciation and amortisation (334.5) (28.8) (1.4) (0.1) (14.1) (378.9) Impairment of property, plant and equipment, net (119.1) 64.8 \u2013 \u2013 \u2013 (54.3) Exploration costs written off\u2075 (1.2) 11.8 \u2013 (70.5) \u2013 (59.9) 1. Segment result is a non-IFRS measure which includes gross pro\ufb01t, exploration costs written off and impairment of property, plant and equipment. See reconciliation below. 2. This is included within the Restructuring costs and other provisions in the Group Income Statement. 3. Unallocated expenditure include amounts of a corporate nature and not speci\ufb01cally attributable to a geographic area. 4. Total liabilities \u2013 Corporate comprise of the Group\u2019s external debt and other non-attributable liabilities. 5. Non-operated segment includes release of $15.3 million indirect tax provision following settlement. 6. Segment revenue and segment result allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classi\ufb01cation of loss on realisation of the cash \ufb02ow hedges within reportable segments. Total balances have remained unchanged. The allocation for the year ended 31 December 2021 increased revenue for Ghana and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the hedging loss of $152.9 million was allocated to Corporate. Total assets and total liabilities allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classi\ufb01cation of tax assets and liabilities within reportable segments. The above balances have been restated by: Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m Total assets \u2013 increase/(decrease) (35.1) 5.4 (6.0) (22.0) 57.8 \u2013 Total liabilities \u2013 (increase)/decrease (32.0) (11.2) 6.0 24.0 13.2 \u2013 In addition, revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. Refer to note 6. Note 1. Segmental reporting continued Sales revenue and non-current assets by origin Sales revenue 2022 $m Sales revenue 2021 Restated2 $m Non-current assets3 2022 $m Non-current assets 3 2021 $m Ghana 1,578.5 1,020.4 3,087.4 3,131.3 Total Ghana 1,578.5 1,020.4 3,087.4 3,131.3 Kenya \u2013 \u2013 258.5 261.7 Total Kenya \u2013 \u2013 258.5 261.7 Argentina \u2013 \u2013 33.6 30.4 C\u00f4te d\u2019Ivoire \u2013 \u2013 2.4 \u2013 Guyana \u2013 \u2013 \u2013 69.1 Total Exploration \u2013 \u2013 36.0 99.5 Gabon 477.0 312.6 132.6 148.7 C\u00f4te d\u2019Ivoire 47.0 46.2 59.2 81.4 Equatorial Guinea1 \u2013 59.1 \u2013 \u2013 Total Non-Operated 524.0 417.9 191.8 230.1 Corporate (319.4) (152.9) 23.4 35.6 Total 1,783.1 1,285.4 3,597.1 3,758.3 1. The disposal of Equatorial Guinea was completed in March 2021 (refer to note 8). 2. Segment revenue allocation between the reportable segments has been restated to correct a prior period error arising from incorrect classi\ufb01cation of loss on realisation of the cash \ufb02ow hedges within reportable segments. Total balances have remained unchanged. The allocation for the year ended 31 December 2021 increased revenue for Ghana and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the hedging loss of $152.9 million was allocated to Corporate. In addition, Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. For the year ended 31 December 2022, this resulted in an increase to revenue in C\u00f4te d\u2019Ivoire of $3.2 million and Gabon of $18.2 million (2021: $5.5 million and $6.7 million, respectively), and a corresponding increase to income tax expense. Refer to note 6. 3. Non-current assets exclude derivative \ufb01nancial instruments and deferred tax assets. ",
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"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-380": {
"value": "Note 2. Total revenue 2022 $m 2021 Restated1 $m Revenue from contracts with customers Revenue from crude oil sales1 2,102.5 1,438.4 Total revenue from contracts with customers 2,102.5 1,438.4 Loss on realisation of cash \ufb02ow hedges (319.4) (153.0) Total revenue 1,783.1 1,285.4 1. Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. Refer to note 6. Finance income has been presented as part of net \ufb01nancing costs (refer to note 5). ",
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"fact-381": {
"value": "Note 3. Staff costs The average annual number of employees employed by the Group worldwide was: 2022 Number 2021 Number Administration 182 192 Technical 194 186 Total 376 378 Note 3. Staff costs continued Staff costs in respect of those employees were as follows: 2022 $m 2021 $m Salaries 66.3 64.3 Social security costs 7.0 10.4 Pension costs 5.3 5.2 Redundancy costs 0.1 3.1 Total staff costs 78.7 83.0 A proportion of the Group\u2019s staff costs shown above is recharged to the Group\u2019s Joint Venture Partners, a proportion is allocated to operating costs and a proportion is capitalised into the cost of \ufb01xed assets under the Group\u2019s accounting policy for exploration, evaluation and production assets with the remainder classi\ufb01ed as an administrative overhead cost in the income statement. The net staff costs recognised in the income statement were $10.5 million (2021: $23.8 million). The Group operates de\ufb01ned contribution pension schemes for staff and Executive Directors. The contributions are payable to external funds which are administered by independent trustees. Contributions during the year amounted to $5.3 million (2021: $5.2 million). Details of Directors\u2019 remuneration, Directors\u2019 transactions and Directors\u2019 interests are set out in the part of the Directors\u2019 Remuneration Report described as having been audited, which forms part of these Financial Statements. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-382": {
"value": "Note 4. Other costs Notes 2022 $m 2021 $m Operating pro\ufb01t is stated after charging/(deducting): Operating costs 266.5 268.7 Depletion and amortisation of oil and gas and leased assets1 10 410.7 360.9 Underlift, overlift and oil stock movements (46.3) (20.0) Royalties 61.7 40.5 Share-based payment charge included in cost of sales 23 0.4 0.5 Other cost of sales 4.4 (11.7) Total cost of sales 697.5 638.9 Share-based payment charge included in administrative expenses 23 5.4 11.1 Depreciation of other \ufb01xed assets 1 10 15.1 18.0 Other administrative costs 30.5 35.0 Total administrative expenses 51.0 64.1 Total restructuring costs and other provisions2 4.2 61.8 Fees payable to the Company\u2019s auditor for: The audit of the Company\u2019s annual accounts 2.1 1.6 The audit of the Company\u2019s subsidiaries pursuant to legislation 0.6 0.8 Total audit services 2.7 2.4 Non-audit services: Audit-related assurance services \u2013 half-year review 0.5 0.5 Corporate \ufb01nance services 1.0 0.4 Other services \u2013 0.1 Total non-audit services 1.5 1.0 Total 4.2 3.6 1. Depreciation expense on leased assets of $60.9 million as per note 10 includes a charge of $3.9 million on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $57.0 million relates to other leased assets and is included within cost of sales. 2. This includes restructuring and redundancy costs of $0.1 million (2021: $3.1 million) as well as movements in other provisions of $4.1 million (2021: $58.7 million). Note 4. Other costs continued Fees payable to Ernst & Young LLP and its associates for non-audit services to the Company are not required to be disclosed because the consolidated Financial Statements are required to disclose such fees on a consolidated basis. Corporate \ufb01nance services are in relation to Class 1 Disposal. Non-audit services were 55% of audit services during the year. Details of the Company\u2019s policy on the use of the auditor for non-audit services, the reasons why the auditor was used rather than another supplier and how the auditor\u2019s independence and objectivity are safeguarded are set out in the Audit Committee Report on pages 63 to 68. No services were provided pursuant to contingent fee arrangements. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-427": {
"value": "Note 5. Net \ufb01nancing costs Notes 2022 $m 2021 $m Interest on bank overdrafts and borrowings 250.4 243.0 Interest on obligations under leases 19 76.4 83.4 Total borrowing costs 326.8 326.4 Finance and arrangement fees 0.3 19.1 Other interest expense 2.4 3.0 Unwinding of discount on decommissioning provisions 20 6.0 7.6 Total \ufb01nance costs 335.5 356.1 Interest income on amounts due from Joint Venture Partners for leases 19 (29.6) (38.8) Other \ufb01nance income (13.3) (5.5) Total \ufb01nance income (42.9) (44.3) Net \ufb01nancing costs 292.6 311.8 ",
"dimensions": {
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"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-414": {
"value": "Note 5. Net \ufb01nancing costs Notes 2022 $m 2021 $m Interest on bank overdrafts and borrowings 250.4 243.0 Interest on obligations under leases 19 76.4 83.4 Total borrowing costs 326.8 326.4 Finance and arrangement fees 0.3 19.1 Other interest expense 2.4 3.0 Unwinding of discount on decommissioning provisions 20 6.0 7.6 Total \ufb01nance costs 335.5 356.1 Interest income on amounts due from Joint Venture Partners for leases 19 (29.6) (38.8) Other \ufb01nance income (13.3) (5.5) Total \ufb01nance income (42.9) (44.3) Net \ufb01nancing costs 292.6 311.8 ",
"dimensions": {
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"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-383": {
"value": "Note 5. Net \ufb01nancing costs Notes 2022 $m 2021 $m Interest on bank overdrafts and borrowings 250.4 243.0 Interest on obligations under leases 19 76.4 83.4 Total borrowing costs 326.8 326.4 Finance and arrangement fees 0.3 19.1 Other interest expense 2.4 3.0 Unwinding of discount on decommissioning provisions 20 6.0 7.6 Total \ufb01nance costs 335.5 356.1 Interest income on amounts due from Joint Venture Partners for leases 19 (29.6) (38.8) Other \ufb01nance income (13.3) (5.5) Total \ufb01nance income (42.9) (44.3) Net \ufb01nancing costs 292.6 311.8 ",
"dimensions": {
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"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-384": {
"value": "Note 6. Taxation on pro\ufb01t on continuing activities Notes 2022 $m 2021 Restated 1 $m Current tax on pro\ufb01ts for the year UK corporation tax (11.8) (19.2) Foreign tax 321.0 162.2 Taxes paid in kind under production sharing contracts 21.4 12.2 Adjustments in respect of prior periods (3.3) (3.3) Total corporate tax 327.3 151.9 UK petroleum revenue tax (2.8) (1.2) Total current tax 324.5 150.7 Deferred tax Origination and reversal of temporary differences UK corporation tax 11.4 18.1 Foreign tax 54.0 80.3 Adjustments in respect of prior periods (2.9) 43.8 Total deferred corporate tax 62.5 142.2 Deferred UK petroleum revenue tax 6.0 2.7 Total deferred tax 21 68.5 144.9 Total income tax expense 393.0 295.6 1. Income tax expense has been restated following a revision to the Group's accounting policy. The revenue from certain Production Sharing Contracts in Gabon and C\u00f4te d\u2019Ivoire is now presented gross of corporate income taxes deemed to have been paid as part of the Government's share of pro\ufb01t oil. This has resulted in an increase to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. This change has been implemented to more accurately represent the income taxes suffered by the Group on its pro\ufb01ts in Gabon and C\u00f4te d\u2019Ivoire and to be more comparable with other entities in the sector. Note 6. Taxation on pro\ufb01t on continuing activities continued The tax rate applied to pro\ufb01t on continuing activities in preparing the reconciliation below is the UK corporation tax rate applicable to the Group\u2019s UK pro\ufb01ts. The difference between the total income tax expense shown above and the amount calculated by applying the standard rate of UK corporation tax applicable to UK pro\ufb01ts of 19% (2021: 19%) to the pro\ufb01t before tax is as follows: 2022 $m 2021 Restated $m Pro\ufb01t from continuing activities before tax 442.1 214.9 Tax on pro\ufb01t from continuing activities at the standard UK corporation tax rate of 19% (2021: 19%) 84.0 40.8 Effects of: Non-deductible exploration expenditurea 0.5 8.5 Other non-deductible expenses 27.8 13.3 Deferred tax asset not recognised b 138.5 94.4 Utilisation of tax losses not previously recognised (0.4) (0.1) Adjustment relating to prior yearsc (6.2) 40.4 Other tax rates applicable outside the UK 214.6 118.3 Other income not subject to corporation tax (0.1) (20.0) Tax impact of acquisition through business combination (note 15) (65.7) \u2013 Total income tax expense for the year 393.0 295.6 a. Includes recurring explorations costs written off where there is no deferred tax impact. b. Includes hedging losses and interest expense. c. Includes movements in provisions in respect of uncertain tax treatments. The Finance Act 2021 sets the Corporation Tax main rate at 19% for the \ufb01nancial year beginning 1 April 2022 and at 25% for the \ufb01nancial year beginning 1 April 2023. These changes were enacted on 10 June 2021 and hence the effect of the change on the deferred tax balances has been included, depending upon when deferred tax is expected to reverse. The Group\u2019s pro\ufb01t before taxation will continue to arise in jurisdictions where the effective rate of taxation differs from that in the UK, such as Ghana (35%) and Gabon convention \ufb01elds (50%), Gabon PSC \ufb01elds (35%) and CDI PSC (25%). Furthermore, there is no tax bene\ufb01t arising on net interest and hedging expense in the UK. Accordingly, the Group\u2019s tax charge will continue to vary according to the jurisdictions in which pre-tax pro\ufb01ts arise. The Group has tax losses of $4,237.4 million (2021: $5,400.0 million) that are available for offset against future taxable pro\ufb01ts in the companies in which the losses arose. Deferred tax assets have not been recognised in respect of losses of $4,128.9 million (2021: $4,749.7 million) as it is not sufficiently probable that there will be future taxable pro\ufb01ts against which these losses can be utilised. The Group has recognised deferred tax assets of $35.8 million (2021: $222.0 million) in relation to tax losses only to the extent of anticipated future taxable income or gains in relevant jurisdictions. The Group has suffered these losses in either the current or preceding period in the tax jurisdiction to which the deferred tax asset relates. The tax losses can be carried forward inde\ufb01nitely. There are no temporary differences relating to unremitted earnings of overseas subsidiaries as the Group is able to control the timing of the reversal of these temporary differences and it is probable that they will not reverse in the foreseeable future. Tax relating to components of other comprehensive income During 2022 nil tax expense (2021: $2.8 million of tax credit) has been recognised through other comprehensive income. ",
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"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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},
"fact-385": {
"value": "Note 7. Earnings /(loss) per ordinary share Basic earnings/(loss) per ordinary share amounts are calculated by dividing net pro\ufb01t/(loss) for the year attributable to ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year. Diluted earnings per ordinary share amounts are calculated by dividing net pro\ufb01t/(loss) for the year attributable to ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of dilutive ordinary shares that would be issued if employee and other share options were converted into ordinary shares. 2022 $m 2021 $m Pro\ufb01t/ (loss) for the year Net pro\ufb01t attributable to equity shareholders 49.1 (80.7) Effect of dilutive potential ordinary shares \u2013 \u2013 Diluted net earnings/ (loss) attributable to equity shareholders 49.1 (80.7) 2022 Number 2021 Number Number of shares Basic weighted average number of shares 1,437,099,966 1,418,378,706 Dilutive potential ordinary shares 48,375,409 45,708,796 Diluted weighted average number of shares 1,485,475,375 1,464,087,502 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-386": {
"value": "Note 8. Asset disposals On 31 March 2021, the Group completed the sale of its assets in Equatorial Guinea with a cash consideration received of $88.9 million. This transaction included contingent future payments of up to $16.0 million which are linked to asset performance and oil price. As per the SPA, a further $5.0 million of additional consideration was also received on completion of Dussafu Marin Permit in Gabon. On 9 June 2021, the Group completed the asset sale of Dussafu Marin Permit in Gabon with a cash consideration received of $39.0 million. This transaction included contingent future payments of up to $24.0 million which are linked to asset performance and oil price. Given Tullow no longer holds interest in the above assets, based on publicly available information the Company has assessed that the asset performance condition is not met. Accordingly, no contingent consideration has been recognised as of 31 December 2022. Book value of assets disposed Equatorial Guinea $m Dussafu $m Total $m Property, plant and equipment 72.9 52.0 124.9 Inventories 6.9 3.2 10.1 Other current assets 68.5 1.7 70.2 Total assets disposed 148.3 56.9 205.2 Trade and other payables (36.1) (18.5) (54.6) Provisions (118.2) (4.7) (122.9) Current tax liabilities (13.6) \u2013 (13.6) Deferred tax liabilities (17.8) \u2013 (17.8) Total liabilities disposed (185.7) (23.2) (208.9) Net (liabilities)/ assets disposed (37.4) 33.7 (3.7) Cash consideration 93.8 39.0 132.8 Transaction costs (11.0) (0.3) (11.3) Gain on disposal1 120.2 5.0 125.2 1. In 2021, in addition to $125.2 million gain on disposals recognised following the Equatorial Guinea and Dussafu disposals, the Group recognised a loss of $5.1 million relating to its sale of Dutch assets to Hague and London Oil plc (HALO) in 2017, and a gain of $0.2 million relating to other transactions during the period which resulted in an overall gain of $120.3 million. No gain on disposals was recognised for the year ended 31 December 2022. Note 8. Asset disposals continued Uganda Contingent asset During 2020, the Group completed the disposal of its interest in Uganda for upfront cash consideration of $500.0 million, with $75.0 million due on FID and contingent future payments linked to oil prices. Given the existing uncertainties around the project, management has concluded that the conditions for recognition of an asset associated with contingent consideration under IFRS 15 were not met as of 31 December 2022. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-387": {
"value": "Note 9. Intangible exploration and evaluation assets 2022 $m 2021 $m At 1 January 354.6 368.2 Additions1 39.2 46.3 Amounts written off (105.2) (59.9) At 31 December 288.6 354.6 1. In Kenya, proceeds from Early Oil Pilot Scheme (EOPS) cargo sales of $6.9 million have been recorded as a credit against capital expenditure. The below table provides a summary of the exploration costs written off on a pre tax basis by country. Country CGU Rationale for 2022 write-off 2022 write-off $m 2022 Remaining recoverable amount $m Guyana Kanuku a, b 75.3 \u2013 Guyana Orinduik b 22.4 \u2013 C\u00f4te d\u2019Ivoire Block 524 c 3.1 \u2013 New Ventures Various d 3.0 \u2013 Other Various 1.4 \u2013 Total write-off 105.2 \u2013 a. Unsuccessful well costs written off. b. Licence relinquishments, expiry, planned exit or reduced activity. c. Current year expenditure on assets previously written off. d. New Ventures expenditure is written off as incurred. In Kenya, the Group had received a 15-month licence extension from September 2020 to December 2021 which was contingent on certain conditions, including submission of a technically and commercially compliant Field Development Plan (FDP). On 10 December 2021, Tullow and its Joint Venture Partners submitted an FDP to the Government of Kenya and ful\ufb01lled its licence obligations. The Group expects a production licence to be granted once due Government process has been completed. Since 1 January 2022, there have been ongoing discussions with the Government of Kenya on approval of the FDP and securing government deliverables. An updated FDP was submitted on 3rd of March and is being reviewed by the Government of Kenya before rati\ufb01cation by the Kenyan Parliament. In addition, the Company continues to progress with the farm down process. In line with its accounting policy, the Group has performed a VIU assessment of the Kenya asset following identi\ufb01cation of triggers for impairment and impairment reversal. This resulted in an NPV signi\ufb01cantly in excess of the book value of $252.6 million. However, the Group has identi\ufb01ed the following estimation uncertainties in respect to the Group\u2019s ability to realise the estimated VIU; receiving and subsequently \ufb01nalising an acceptable offer from a strategic partner and securing governmental approvals relating thereto, obtaining \ufb01nancing for the project and government deliverables. These items require satisfactory resolution before the Group can take a Final Investment Decision. Due to the binary nature of these uncertainties the Group was unable to either adjust the cash \ufb02ows or discount rate appropriately. It has therefore used its judgement and assessed a probability of achieving FID and therefore the recognition of commercial reserves. This probability was applied to the VIU to determine a risk adjusted VIU and compared against the net book value of the asset. Based on this there is no impairment or impairment reversal as at 31 December 2022. The cash \ufb02ows in the VIU assessment were discounted using a pre- tax nominal r discount rate of 20%. Refer to note 10 for oil price assumptions. Note 9. Intangible exploration and evaluation assets continued Should the uncertainties around the project be resolved, there will be a reversal of a previously recorded impairment. However, if the uncertainties are not resolved there will be an additional impairment of $252.6 million. A reduction or increase in the two-year forward curve of $5/bbl, based on the approximate range of annualised average oil price over recent history, and a reduction or increase in the medium and long-term price assumptions of $5/bbl, based on the range of annualised average historical prices, are considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices speci\ufb01ed above would result in an impairment charge of $31.6 million, whilst increases to oil prices speci\ufb01ed above would result in an impairment reversal of $35.2 million. A 1% change in the pre-tax discount rate would result in an impairment charge of $34.2 million. The Group believes a 1% change in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group\u2019s and a peer group of companies\u2019 impairments. Refer to Note 26 for Net Zero Emission scenarios. Country CGU Rationale for 2021 write-off 2021 write-off $m 2021 Remaining recoverable amount $m Suriname Blocks 47 and 62 b,d 58.9 \u2013 Uganda Exploration areas 1,1A, 2 and 3A c (15.3) \u2013 Gabon Tchatamba d 2.2 \u2013 Peru Licences Z67 and Z68 b 1.8 \u2013 C\u00f4te d\u2019Ivoire Block 520 b 6.6 \u2013 Other Various a 5.7 \u2013 Total write-off 59.9 \u2013 a. Current year expenditure on assets previously written off. b. Licence relinquishments, expiry, planned exit or reduced activity. c. Release of indirect tax provision following settlement. d. Unsuccessful well costs written off. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory",
"language": "en",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-388": {
"value": "Note 10. Property, plant and equipment Notes 2022 Oil and gas assets $m 2022 Other \ufb01xed assets $m 2022 Right of use assets $m 2022 Total $m 2021 Oil and gas assets $m 2021 Other \ufb01xed assets $m 2021 Right of use assets $m 2021 Total $m Cost At 1 January 10,521.7 69.5 1,091.7 11,682.9 10,460.2 69.6 1,018.6 11,548.4 Additions 1 305.2 2.0 63.5 370.7 73.0 1.6 73.5 148.1 Acquisitions1 15 473.2 \u2013 \u2013 473.2 Transfer 2 15 \u2013 \u2013 86.6 86.6 Asset retirement \u2013 (38.1) (41.7) (79.8) \u2013 (1.4) \u2013 (1.4) Currency translation adjustments (117.5) (3.4) (3.3) (124.2) (11.5) (0.3) (0.4) (12.2) At 31 December 11,182.6 30.0 1,196.8 12,409.4 10,521.7 69.5 1,091.7 11,682.9 Depreciation, depletion, amortisation and impairment At 1 January (8,263.7) (53.8) (450.8) (8,768.3) (7,915.9) (42.3) (352.3) (8,310.5) Charge for the year 4 (353.7) (11.2) (60.9) (425.8) (304.9) (13.4) (60.6) (378.9) Impairment loss (391.2) \u2013 \u2013 (391.2) (54.3) \u2013 \u2013 (54.3) Capitalised depreciation \u2013 \u2013 (46.1) (46.1) \u2013 \u2013 (38.0) (38.0) Asset retirement \u2013 38.1 41.7 79.8 \u2013 1.4 \u2013 1.4 Currency translation adjustments 120.2 2.5 0.9 123.6 11.4 0.5 0.1 12.0 At 31 December (8,888.4) (24.4) (515.2) (9,428.0) (8,263.7) (53.8) (450.8) (8,768.3) Net book value at 31 December 2,294.2 5.6 681.6 2,981.4 2,258.0 15.7 640.9 2,914.6 1. This relates to an acquisition through business combination discussed in Note 15. 2. As a result of Ghana pre-emption a proportionate amount has been reclassi\ufb01ed from receivables due from joint venture partners to right of use assets relating to the Group\u2019s existing interest in lease contracts in the joint operation. The currency translation adjustments arose due to the movement against the Group\u2019s presentational currency, USD, of the Group\u2019s UK assets, which have a functional currency of GBP. Note 10. Property, plant and equipment continued During 2022 and 2021 the Group applied the following nominal oil price assumptions for impairment assessments: Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 onwards 2022 $84/bbl $79/bbl $70/bbl $70/bbl $70/bbl $70/bbl in\ufb02ated at 2% 2021 $76/bbl $71/bbl $68/bbl $65/bbl $65/bbl $65/bbl in\ufb02ated at 2% Trigger for 2022 impairment/ (reversal) 2022 Impairment/ (reversal) $m Pre-tax discount rate assumption 2022 Remaining recoverable amount d $m Limande and Turnix CGU (Gabon) a (1.6) 15% 44.6 Tchatamba (Gabon) a (1.3) 15% 38.0 Oba and Middle Oba CGU (Gabon) a (0.4) 17% 11.8 Echira, Niungo and Igongo (Gabon) a (1.4) 17% 8.6 TEN (Ghana) b 380.6 13% 931.7 Mauritania a 12.8 n/a \u2013 UK CGU a,c 2.5 n/a \u2013 Impairment 391.2 a. Change to decommissioning estimate. b. Revision of value based on revisions to reserves c. The \ufb01elds in the UK are grouped into one CGU as all \ufb01elds within those countries share critical gas infrastructure. d. The remaining recoverable amount of the asset is its value in use. Impairments identi\ufb01ed in the TEN \ufb01elds of $380.6 million were primarily due to lower 2P reserves partially offset by oil price assumptions. Oil prices stated above are benchmark prices to which an individual \ufb01eld price differential is applied. All impairment assessments are prepared on a VIU basis using discounted future cash \ufb02ows based on 2P reserves pro\ufb01les. A reduction or increase in the two-year forward curve of $5/bbl, based on the approximate range of annualised average oil price over recent history, and a reduction or increase in the medium and long-term price assumptions of $5/bbl, based on the range of annualised average historical prices, are considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices speci\ufb01ed above would increase the impairment charge by $131.4 million for Ghana and increase the impairment by $19.2 million for Non-Operated, whilst increases to oil prices speci\ufb01ed above would result in a credit to the impairment charge of $122.0 million for Ghana and no change to Non-Operated. A 1% change in the pre-tax discount rate would increase the impairment by $33.0 million for Ghana and increase the impairment by $2.9 million for Non-Operated. The Group believes a 1% change in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group\u2019s and peer group of companies\u2019 impairments. For Net Zero Emissions sensitivities refer to Note 26. Trigger for 2021 impairment/ (reversal) 2021 Impairment/ (reversal) $m Pre tax discount rate assumption 2021 Remaining recoverable amount $m Limande and Turnix CGU (Gabon) a,c (40.8) 13% 50.8 Ezanga (Gabon) a,c (17.0) 15% 22.4 Oba and Middle Oba CGU (Gabon) a,c (3.2) 15% 10.5 Espoir (C\u00f4te d\u2019Ivoire) a,c (8.7) 10% 81.4 TEN (Ghana) a,b,c 119.1 10% 1,171.4 Mauritania b 2.1 n/a \u2013 UK CGU b,d 2.8 n/a \u2013 Impairment 54.3 a. Increase to short, medium and long-term oil price assumptions. b. Change to decommissioning estimate. c. Revision of value based on revisions to reserves. d. The \ufb01elds in the UK are grouped into one CGU as all \ufb01elds within those countries share critical gas infrastructure. e. The remaining recoverable amount of the asset is its value in use. Note 10. Property, plant and equipment continued Impairments identi\ufb01ed in the TEN \ufb01elds of $119.1 million were primarily due to lower TEN 2P reserves and higher capital expenditure partially offset by price and lower decommissioning costs. This is offset by impairment reversals mainly in Gabon of $61.1 million and Espoir of $8.7 million as a result of higher oil prices and higher 2P reserves. Oil prices stated above are benchmark prices to which an individual \ufb01eld price differential is applied. All impairment assessments are prepared on a VIU basis using discounted future cash \ufb02ows based on 2P reserves pro\ufb01les. A reduction or increase in the two-year forward curve of $5/bbl, based on the approximate range of annualised average oil price over recent history, and a reduction or increase in the medium and long-term price assumptions of $5/bbl, based on the range of annualised average historical prices, are considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices speci\ufb01ed above would increase the impairment charge by $157.7 million for Ghana and reduce the impairment reversal by $12.4 million for Non-Operated, whilst increases to oil prices speci\ufb01ed above would result in a credit to the impairment charge of $157.7 million for Ghana and increase the impairment reversal by $1.3 million for Non-Operated. A 1% increase in the pre-tax discount rate would increase the impairment by $40.7 million for Ghana and reduce the impairment reversal by $3.3 million for Non-Operated. The Group believes a 1% change in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group\u2019s and peer group of companies\u2019 impairment. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-389": {
"value": "Note 11. Other assets Notes 2022 $m 2021 $m Non-current Amounts due from Joint Venture Partners 19 323.3 486.0 VAT recoverable 3.8 3.1 327.1 489.1 Current Amounts due from Joint Venture Partners 19 452.3 554.7 Underlifts 76.2 26.7 Prepayments 31.3 49.6 Other current assets 8.1 73.5 567.9 704.5 895.0 1,193.6 The decrease in non-current receivables from JV Partners compared to December 2021 mainly relates to reduction in time remaining on the TEN FPSO lease, net decrease in GNPC (Ghana National Petroleum Corporation) receivable and reduction in partner share following Ghana pre-emption. The movement in current receivables from JV Partners relates mainly to timing of partner balances and reduction in partner share following Ghana pre-emption. The decrease in other current assets compared to 2021 is mainly due to a collection of the deferred consideration relating to the Uganda disposal in March 2022 ($67.9 million net ). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfOtherAssetsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-390": {
"value": "Note 12. Inventories 2022 $m 2021 $m Warehouse stock and materials 69.1 55.5 Oil stock 112.5 79.3 181.6 134.8 The increase in oil stock is associated with the timing of liftings of the Group's share of crude oil around period end. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInventoriesExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-391": {
"value": "Note 13. Trade receivables Trade receivables comprise amounts due for the sale of oil. They are generally due for settlement within 30\u201360 days and are therefore all classi\ufb01ed as current. The Group holds the trade receivables with the objective of collecting the contractual cash \ufb02ows and therefore measures them subsequently at amortised cost using the effective interest method. The balance of trade receivables as at 31 December 2022 of $26.8 million (2021:$99.8 million) mainly relates to oil sales in Gabon for liftings between September and December 2022. The December Jubilee (Ghana) sale was settled before 31 December 2022. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-392": {
"value": "Note 14. Cash and cash equivalents Notes 2022 $m 2021 $m Cash at bank 305.3 226.1 Short-term deposits and other cash equivalents 331.0 243.0 636.3 469.1 Cash and cash equivalents includes an amount of $74.7 million (2021: $92.4 million) which the Group holds as operator in Joint Venture bank accounts. Included within cash at bank is $7.0 million (2021: $0.8 million) held in restricted bank accounts. This mainly consists of $4.5 million held as security for performance bonds relating to work commitments on exploration licences. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-393": {
"value": "Note 15. Business combination On 17 March 2022 the Group completed the pre-emption related to the sale of Occidental Petroleum\u2019s (\u201cOxy\u201d) interests in the Jubilee and TEN \ufb01elds in Ghana to Kosmos Energy. As a result of this acquisition, the Group\u2019s interest in the TEN \ufb01elds increased from 47.18% to 54.84%, and from 35.48% to 39.0% in the Jubilee \ufb01eld. Tullow did not obtain control as a result of this transaction, as all joint venture partners retain joint control. The total purchase consideration, which was funded from cash on the balance sheet, comprises of $118.2 million cash settled on completion, and $8.6 million subsequent post-completion adjustment paid in May 2022. There is no element of contingent consideration included in the purchase price. The fair values of the identi\ufb01able assets and liabilities acquired were: Fair value recognised on acquisition $m Property, plant and equipment 473.2 Inventories 12.1 Other current assets 31.4 Total assets acquired 516.7 Trade and other payables (10.5) Provisions (61.6) Deferred tax liabilities (143.6) Total liabilities assumed (215.5) Net identi\ufb01able assets acquired 301.0 Purchase consideration transferred (126.8) Deemed settlement of provision 22.6 Gain on bargain purchase 196.8 There were no acquisitions in the year ended 31 December 2021. The property, plant and equipment acquired through the business combination has been recognised at the fair value based on the net present value of the discounted future cash \ufb02ows. Signi\ufb01cant inputs to the valuation include short- and long-term commodity prices, reserve estimates, production volume pro\ufb01les, planned development expenditure, cost pro\ufb01les and discount rates, and are consistent with those applied by the management when testing assets for impairments. The fair value of acquired other receivables is nil. The gross contractual amount for other receivables due is $0.9 million, with a loss allowance of $0.9 million recognised on acquisition. The deferred tax liability mainly comprises the tax effect of the accelerated depreciation for tax purposes of tangible assets. Contingent liabilities recognised in a business combination A contingent liability recognised in a business combination is initially measured at its fair value. Subsequently, it is measured at the higher of the amount that would be recognised in accordance with the requirements for provisions as per IAS 37 \u201cProvisions, Contingent Liabilities and Contingent Assets\u201d, or the amount initially recognised less (when appropriate) cumulative amortisation recognised in accordance with the requirements for revenue recognition. Note 15. Business combination continued As part of the pre-emption Tullow has taken on pro-rated exposure relating to Anadarko WCTP Company\u2019s (\u201cAnadarko\u201d) BPRT and AOE disputed claims. In February 2018, Anadarko, whom Oxy acquired the interests from, received a provisional assessment for AOE for US$346.6 million, including a penalty of $329.5 million, (the portion of this claim related to Tullow\u2019s acquired interests was $67.2 million) covering \ufb01nancial years 2006 \u2013 2016 and in November 2018 the Ministry of Finance con\ufb01rmed that the assessment was suspended pending the Government reaching a \ufb01nal view on the basis for calculating AOE. Anadarko continued to dispute the AOE assessment issued and considered no AOE was payable for these periods. In September 2021, Anadarko received a revised tax audit report from the Ghana Revenue Authority (GRA) for the \ufb01nancial years 2014 to 2018 including a $228.3 million branch pro\ufb01ts remittance tax (BPRT) assessment (including late payment interest of $52.1 million) (the portion of this claim related to Tullow\u2019s acquired interests was $67.1 million). The Anadarko BPRT assessment is covered by a Notice of Dispute issued in June 2020. A contingent liability at fair value of $36.8 million was recognised at the acquisition date for provisions resulting from certain contractual indemnities. There was no change in provision as at 31 December 2022. Revenue and net pro\ufb01t contribution The acquired business contributed revenues of $133.2 million and net pro\ufb01t of $19.6 million to the Group for the period from 17 March 2022 to 31 December 2022. If the acquisition had occurred on 1 January 2022, the consolidated pro-forma revenues would have been $169.2 million higher and the consolidated pro-forma pro\ufb01t for the period ended 31 December 2022 would have been higher by $11.4 million. These amounts have been calculated using the acquired interest\u2019s results and adjusting them for the additional depreciation and amortisation that would have been charged assuming the fair value adjustments to property, plant and equipment had applied from 1 January 2022, together with the consequential tax effects. Acquisition-related costs Acquisition-related costs of $0.6 million are included in administrative expenses in the statement of pro\ufb01t or loss and in operating cash \ufb02ows in the statement of cash \ufb02ows. Recognition of gain on bargain purchase The difference between the fair value of net assets acquired and consideration paid was recognised within the income statement as gain on bargain purchase of $196.8 million. This is mostly due to the change in the oil markets from 2021, when the transaction between Occidental Petroleum and Kosmos Energy was negotiated to March 2022, when the acquisition was completed by Tullow. The consideration paid by Tullow for the acquired interest was based on the proportionate consideration agreed between Occidental Petroleum and Kosmos Energy, subject to completion adjustments. Additionally, the original transaction between the two parties was driven by the seller\u2019s intention to leave the region and dispose of the non-core elements of the portfolio which it had acquired from Anadarko Petroleum in August 2019. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-394": {
"value": "Note 16. Trade and other payables Current liabilities Notes 2022 $m 2021 $m Trade payables 68.4 60.2 Other payables 51.4 57.4 Overlifts \u2013 0.7 Accruals\u00b9 379.3 381.3 Current portion of lease liabilities 19 251.2 251.5 750.2 751.1 1. Accruals mainly relate to capital expenditure, interest expense on bonds and staff-related expenses. Non-current liabilities Notes 2022 $m 2021 $m Other non-current liabilities\u00b9 47.1 75.2 Non-current portion of lease liabilities 19 732.9 911.9 780.0 987.1 1. Other non-current liabilities include balances related to JV Partners. Trade and other payables are non-interest bearing except for leases (note 19). Payables related to operated Joint Ventures (primarily in Ghana and Kenya) are recorded gross with the amount representing the partners\u2019 share recognised in amounts due from Joint Venture Partners (note 11). The change in trade payables and in other payables predominantly represents timing differences and levels of work activity. The decrease in non-current portion of lease liabilities mainly relates to reduction in time remaining on the TEN FPSO lease. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-395": {
"value": "Note 17. Borrowings 2022 $m 2021 $m Current Borrowings \u2013 within one year 10.25% Senior Secured Notes due 2026 100.0 100.0 100.0 100.0 2022 $m 2021 $m Non-current Borrowings \u2013 after one year but within \ufb01ve years 7.00% Senior Notes due 2025 792.8 792.1 10.25% Senior Secured Notes due 2026 1,580.0 1,676.6 2,372.8 2,468.7 Carrying value of total borrowings 2,472.8 2,568.7 The Group\u2019s capital structure includes $1.7bn Senior Secured Notes (2026 Notes), $800 million Senior notes due 2025 (2025 Notes) and a $500 million Super Senior Revolving Credit Facility (SSRCF) which will primarily be used for working capital purposes. The 2026 Notes, maturing in May 2026, require an annual prepayment of $100 million, in May, of the outstanding principal amount plus accrued and unpaid interest, with the balance due on maturity. On 16 May 2022, the Group made the annual prepayment of $100 million of the 2026 Notes, which reduced total debt to $2.5 billion. The 2025 Notes are due in a single payment in March 2025. The SSRCF, maturing in December 2024, comprises of (i) a $500 million revolving credit facility and (ii) a $100 million letter of credit facility. The revolving credit facility remains undrawn as at 31 December 2022. Letters of credit amounting to $44 million (2021: $20 million) have been issued under the facility. Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes and the SSRCF are $20.0 million, $7.0 million and $4.8 million respectively. The 2026 Notes and the SSRCF are senior secured obligations of Tullow Oil Plc and are guaranteed by certain of the subsidiaries of the Group. Capital management The Group de\ufb01nes capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and bene\ufb01ts to stakeholders and to safeguard the Group\u2019s ability to continue as a going concern. Tullow is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Group may put in place new debt facilities, issue new shares for cash, repay debt, engage in active portfolio management, adjust the dividend payment to shareholders, or undertake other such restructuring activities as appropriate. The Group monitors capital on the basis of the gearing, being net debt divided by adjusted EBITDAX, and maintains a policy target of less than 1x. SSRCF covenants The SSRCF does not have any \ufb01nancial maintenance covenants. Availability under the $500 million cash tranche of the facility is determined on an annual basis with reference to the Net Present Value of the 2P reserves of the Group (2P NPV) at the end of the preceding calendar year. SSRCF debt capacity is calculated as 2P NPV divided by 1.1x less senior secured debt outstanding. Note 17. Borrowings continued 2025 Notes and 2026 Notes covenants The 2025 Notes and the 2026 Notes are subject to customary high yield covenants including limitations on debt incurrence, asset sales and restricted payments such as prepayments of junior debt and dividends. Key covenants in the current business cycle are considered to be those related to debt incurrence and restricted payments. For de\ufb01nitions of the capitalised terms used in the following paragraphs please refer to the offering memorandum of the 2025 Notes and/or the 2026 Notes. Tullow is permitted to incur additional debt if the ratio of Consolidated Cash Flow to Fixed Charges for the previous 12 months is at least 2.25 times on a pro forma basis. Tullow is permitted to incur secured debt if the 2P Reserves Coverage Ratio is at least 2.0 times on a pro forma basis. Subject to certain conditions, Tullow is permitted to incur debt to re\ufb01nance the 2025 Notes on a like for like basis, i.e. subordinated to the 2026 Notes. Tullow would be permitted to make payments towards the 2025 Notes amounting to the greater of $100 million per year and 50% of the Consolidated Net Income of the Company for the period from 1 January 2021 to the end of the most recently completed \ufb01scal half-year for which internal \ufb01nancial statements are available if, after giving pro forma effect to the payment(s) if the 2P Reserves Coverage Ratio is equal to or greater than 1.5 times. Tullow would be permitted to make payments towards the 2025 Notes amounting to the greater of $100 million per year, 50% of the Consolidated Net Income of the Company for the period from 1 January 2021 to the end of the most recently completed \ufb01scal half-year for which internal \ufb01nancial statements are available and 100% of Consolidated Cash Flow per year if the 2P Reserves Coverage Ratio is equal to or greater than 2.0 times and the Consolidated Leverage Ratio is less than 1.5 times. The Company or its affiliates may, at any time and from time to time, seek to retire or purchase outstanding debt through cash purchases and/or exchanges, in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will be upon such terms and at such prices as management may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. ",
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"concept": "ifrs-full:DisclosureOfBorrowingsExplanatory",
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},
"fact-415": {
"value": "Note 18. Financial instruments Financial risk management objectives The Group\u2019s Corporate Treasury function provides services to the business, coordinates access to international \ufb01nancial markets, monitors and manages the \ufb01nancial risks relating to the operations of the Group through internal management reports which analyse exposures by degree and magnitude of risks. These risks include market risk (including currency risk, interest rate risk and price risk), credit risk and liquidity risk. The Group seeks to minimise the effects of these risks by using derivative \ufb01nancial instruments to hedge these risk exposures, if deemed appropriate. The use of \ufb01nancial derivatives is governed by the Group\u2019s policies approved by the Board of Directors. Compliance with policies and exposure limits are monitored and reviewed internally on a regular basis. The Group does not enter into or trade \ufb01nancial instruments, including derivatives, for speculative purposes. 2022 $m 2021 $m Financial assets Financial assets at amortised cost Trade receivables 26.8 99.8 Amounts due from Joint Venture Partners 775.6 1,040.7 Cash and cash equivalents 636.3 469.1 1,438.7 1,609.6 Financial liabilities Liabilities at amortised cost Trade payables 115.4 135.2 Other payables 430.7 439.4 Borrowings 2,472.8 2,568.7 Lease liabilities 984.1 1,163.4 Derivative \ufb01nancial instruments Used for hedging 244.2 179.9 4,247.3 4,486.6 ",
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"concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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},
"fact-396": {
"value": "Note 18. Financial instruments Financial risk management objectives The Group\u2019s Corporate Treasury function provides services to the business, coordinates access to international \ufb01nancial markets, monitors and manages the \ufb01nancial risks relating to the operations of the Group through internal management reports which analyse exposures by degree and magnitude of risks. These risks include market risk (including currency risk, interest rate risk and price risk), credit risk and liquidity risk. The Group seeks to minimise the effects of these risks by using derivative \ufb01nancial instruments to hedge these risk exposures, if deemed appropriate. The use of \ufb01nancial derivatives is governed by the Group\u2019s policies approved by the Board of Directors. Compliance with policies and exposure limits are monitored and reviewed internally on a regular basis. The Group does not enter into or trade \ufb01nancial instruments, including derivatives, for speculative purposes. 2022 $m 2021 $m Financial assets Financial assets at amortised cost Trade receivables 26.8 99.8 Amounts due from Joint Venture Partners 775.6 1,040.7 Cash and cash equivalents 636.3 469.1 1,438.7 1,609.6 Financial liabilities Liabilities at amortised cost Trade payables 115.4 135.2 Other payables 430.7 439.4 Borrowings 2,472.8 2,568.7 Lease liabilities 984.1 1,163.4 Derivative \ufb01nancial instruments Used for hedging 244.2 179.9 4,247.3 4,486.6 Note 18. Financial instruments continued Fair values of \ufb01nancial assets and liabilities With the exception of the 2026 Notes and the 2025 Notes, the Group considers the carrying value of all its \ufb01nancial assets and liabilities to be materially the same as their fair value. The fair value of the 2026 Notes and 2025 Notes as determined using market value at 31 December 2022, was $1,364.8 million (2021: $1,814.2 million) and $490.0 million (2021: $661.0 million) respectively. These are compared to their carrying value of $1,680.0 million (2021: $1,776.7 million) and $792.9 million (2021: $792.1 million). The 2026 Notes and the 2025 Notes are categorised as level 1 in the fair value hierarchy. The Group has no material \ufb01nancial assets that are past due. No material \ufb01nancial assets are impaired at the balance sheet date. All \ufb01nancial assets and liabilities with the exception of derivatives are measured at amortised cost. Fair values of derivative instruments All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash \ufb02ow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm\u2019s-length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved. The Group\u2019s derivative carrying and fair values were as follows: Assets/liabilities 2022 Less than 1 year $m 2022 1\u20133 years $m 2022 Total $m 2021 Less than 1 year $m 2021 1\u20133 years $m 2021 Total $m Cash \ufb02ow hedges Oil derivatives (162.1) (49.7) (211.8) (56.7) (66.5) (123.2) (162.1) (49.7) (211.8) (56.7) (66.5) (123.2) Deferred premium Oil derivatives (24.2) (8.2) (32.4) (24.3) (32.4) (56.7) (24.3) (32.4) (56.7) Total assets \u2013 \u2013 \u2013 \u2013 \u2013 \u2013 Total liabilities (186.3) (57.9) (244.2) (81.0) (98.9) (179.9) Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide. The following provides an analysis of the Group\u2019s \ufb01nancial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable: Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities; Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data. All the Group\u2019s derivatives are Level 2 (2021: Level 2). There were no transfers between fair value levels during the year. For \ufb01nancial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by re-assessing categorisation (based on the lowest-level input which is signi\ufb01cant to the fair value measurement as a whole) at the end of each reporting period. Note 18. Financial instruments continued Offsetting of \ufb01nancial instruments Financial assets and liabilities are offset and the net amount is reported in the Group balance sheet when there is a legally enforceable right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously. No material enforceable master netting agreements were identi\ufb01ed. The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts recognised for \ufb01nancial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the Group balance sheet. 31 December 2022 Gross amounts recognised $m Gross amounts offset in Group balance sheet $m Net amounts presented in Group balance sheet $m Derivative assets \u2013 \u2013 \u2013 Derivative liabilities (244.2) \u2013 (244.2) 31 December 2021 Gross amounts recognised $m Gross amounts offset in Group balance sheet $m Net amounts presented in Group balance sheet $m Derivative assets 0.2 (0.2) \u2013 Derivative liabilities (180.1) 0.2 (179.9) Commodity price risk The Group uses a number of derivatives to mitigate the commodity price risk associated with its underlying oil revenue. Such commodity derivatives tend to be priced using benchmarks, such as Dated Brent, which correlate as far as possible to the underlying oil revenue. There is an economic relationship between the hedged items and the hedging instruments due to a common underlying, i.e. Dated Brent, between them. Forecast oil sales, which are based on Dated Brent, are hedged with options which have Dated Brent as reference price. An increase in Dated Brent will cause the value of the hedged item and hedging instrument to move in opposite directions. The Group has established a hedge ratio of 1:1 for the hedging relationships as the underlying risk of the commodity derivatives is identical to the hedged risk components. To test the hedge effectiveness, the Group uses the hypothetical derivative method and compares the changes in the fair value of the hedging instruments against the changes in fair value of the hedged items attributable to the hedged risks. The Group hedges its estimated oil revenues on a portfolio basis, aggregating its oil revenues from substantially all of its African oil interests. As at 31 December 2022 and 31 December 2021, all of the Group\u2019s oil derivatives have been designated as cash \ufb02ow hedges. The Group\u2019s oil hedges have been assessed to be highly effective. Financial risk management is adopted centrally for the Group. The Group adopts a risk component hedging strategy. This results from designating the variability in all the cash \ufb02ows attributable to the change in the benchmark price per the oil sales contracts where the critical terms of the hedged item and hedging instrument match. The following table demonstrates the timing, volumes and average \ufb02oor price protected for the Group\u2019s commodity hedges: Hedging position as at 31 December 2022 2023 2024 Oil volume (bopd) 33,095 11,305 Average \ufb02oor price protected ($/bbl) 55.0 55.0 Hedging position as at 31 December 2021 2022 2022 Oil volume (bopd) 42,462 33,095 Average \ufb02oor price protected ($/bbl) 51.37 55.00 Note 18. Financial instruments continued The following table demonstrates the hedge position as at 31 December 2022: 2023 hedge position at 31 December 2022 Bopd Bought put (\ufb02oor) Sold call Bought call Hedge structure Collars 33,095 $55.00 $74.62 \u2013 Zero cost dollars \u2013 \u2013 \u2013 \u2013 Straight Puts \u2013 \u2013 \u2013 \u2013 Total/weighted average 33,095 $55.00 $74.62 \u2013 2024 hedge position at 31 December 2022 Bopd Bought put (\ufb02oor) Sold call Bought call Hedge structure Collars 11,305 $55.00 $74.63 \u2013 Total/weighted average 11,305 $55.00 $74.63 \u2013 The following table demonstrates the sensitivity of the Group\u2019s derivative \ufb01nancial instruments to reasonably possible movements in Dated Brent oil prices: Effect on equity Market movement as at 31 Dec 2022 2022 $m 2021 $m Brent oil price 25% (464.4) (416.2) Brent oil price (25%) \u2013 41.1 The following assumptions have been used in calculating the sensitivity in movement of the oil price: the pricing adjustments relate only to the point forward mark-to-market (MTM) valuations, the price sensitivities assume there is no ineffectiveness related to the oil hedges and the sensitivities have been run only on the intrinsic element of the hedge as Management considers this to be the material component of oil hedge valuations. Hedge reserve summary The hedge reserve represents the portion of deferred gains and losses on hedging instruments deemed to be effective cash \ufb02ow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the cash \ufb02ow hedge reserve by intrinsic and time value, net of tax effects: Cash \ufb02ow hedge reserve 2022 $m 2021 $m Oil derivatives \u2013 intrinsic (150.3) (39.5) Oil derivatives \u2013 time value (94.4) (146.7) The deferred gains and losses in the hedge reserve are subsequently transferred to the income statement at maturity of derivative contracts. The tables below show the impact on the hedge reserve and on sales revenue during the year: Deferred amounts in the hedge reserve \u2013 intrinsic 2022 $m 2021 $m At 1 January (39.3) 4.8 Reclassi\ufb01cation adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 288.5 112.3 Revaluation (losses)/gains arising in the year (399.5) (159.1) Movement in current and deferred tax \u2013 2.7 (110.8) (44.3) At 31 December (150.3) (39.3) Note 18. Financial instruments continued Hedge reserve summary Deferred amounts in the hedge reserve \u2013 time value 2022 $m 2021 $m At 1 January (146.9) (5.4) Reclassi\ufb01cation adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 30.8 40.7 Revaluation losses arising in the year 21.7 (182.3) Movement in current and deferred tax \u2013 0.1 52.5 (141.5) At 31 December (94.4) (146.9) Reconciliation to sales revenue 2022 $m 2021 $m Oil derivatives \u2013 transferred to sales revenue 288.5 112.3 Deferred premium paid 30.8 40.7 Net losses/(gain) from commodity derivatives in sales revenue (note 2) 319.3 153.0 Interest rate risk Interest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market interest rates. During part of the \ufb01nancial year 2021, the Group was exposed to interest rate risk as it borrowed funds at both \ufb01xed and \ufb02oating interest rates. Following the debt re\ufb01nancing in May 2021, all of the Group\u2019s borrowings are \ufb01xed interest bearing. The Super Senior Revolving Credit Facility is based on \ufb02oating interest rates and remains undrawn as at 31 December 2022. Fixed rate debt comprises 2025 Notes and 2026 Notes. The interest rate pro\ufb01le of the Group\u2019s \ufb01nancial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2022 and 2021, was as follows: 2022 Cash and cash equivalents $m 2022 Fixed rate debt $m 2022 Total $m 2021 Cash and cash equivalents $m 2021 Fixed rate debt $m 2021 Total $m US$ 578.1 (2,500.0) (1,921.9) 376.2 (2,600.0) (2,223.8) Euro 0.3 \u2013 0.3 1.3 \u2013 1.3 Sterling 16.3 \u2013 16.3 85.4 \u2013 85.4 XAF 38.8 \u2013 38.8 \u2013 \u2013 Other 2.8 \u2013 2.8 6.2 \u2013 6.2 636.3 (2,500.0) (1,863.7) 469.1 (2,600.0) (2,130.9) Cash and cash equivalents consisted of $230.7 million (2021: $159.9 million) of deposits which earn interest at rates set in advance for periods ranging from overnight to three months by reference to market rates. The sensitivity of the Group\u2019s \ufb01nancial instruments to reasonably possible movements in interest rates is considered not material. Note 18. Financial instruments continued Credit risk The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and speci\ufb01c transaction approvals. The Group limits its counterparty credit risk on cash and cash equivalent balances by dealing only with \ufb01nancial institutions with credit ratings of at least A or equivalent. The primary credit exposures for the Group are its receivables generated by the marketing of crude oil and amounts due from JV Partners (including in relation to their share of the TEN FPSO lease). These exposures are managed at the corporate level. The Group\u2019s crude sales are predominantly made to international oil market participants including the oil majors, trading houses and re\ufb01neries. JV Partners are predominantly international major oil and gas market participants. Counterparty evaluations are conducted utilising international credit rating agency and \ufb01nancial assessments. Where considered appropriate, security in the form of trade \ufb01nance instruments from \ufb01nancial institutions with an appropriate credit rating, such as letters of credit, guarantees and credit insurance, are obtained to mitigate the risks. The Group generally enters into derivative agreements with banks which are lenders under the SSRCF. The Group does not have any signi\ufb01cant credit risk exposure to any single counterparty or any group of counterparties. The maximum \ufb01nancial exposure due to credit risk on the Group\u2019s \ufb01nancial assets, representing the sum of cash and cash equivalents, investments, derivative assets, trade receivables, and receivables from Joint Venture Partners, as at 31 December 2022 was $1,438.7 million (2021: $1,609.6 million). Foreign currency risk The Group conducts and manages its business predominantly in US dollars, the functional currency of the industry in which it operates. The Group also purchases the functional currencies of the countries in which it operates routinely on the spot market. From time to time the Group undertakes transactions denominated in other currencies arising from certain operating and capital expenditure incurred in currencies other than US dollars; these exposures are often managed by executing foreign currency \ufb01nancial derivatives. There were no foreign currency \ufb01nancial derivatives in place as at 31 December 2022 (2021: nil). Cash balances are held in other currencies to meet immediate operating and administrative expenses or to comply with local currency regulations. As at 31 December 2022, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $58.1 million in non-US dollar-denominated cash and cash equivalents (2021: $46.9 million). The following table demonstrates the sensitivity of the Group\u2019s \ufb01nancial instruments to reasonably possible movements in US dollar exchange rates: Effect on pro\ufb01t before tax Effect on equity Market movement 2022 $m 2021 $m 2022 $m 2021 $m US$/foreign currency exchange rates 20% 9.7 (7.8) 9.7 (7.8) US$/foreign currency exchange rates (20%) (14.5) 11.7 (14.7) 11.7 Liquidity risk The Group manages its liquidity risk using both short-term and long-term cash \ufb02ow projections, supplemented by debt \ufb01nancing plans and active portfolio management across the Group. Ultimate responsibility for liquidity risk management rests with the Board of Directors, which has established an appropriate liquidity risk management framework covering the Group\u2019s short, medium and long-term funding and liquidity management requirements. The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets and delays to development projects. The Group had $1.1 billion (2021: $0.9 billion) of total facility headroom and free cash as at 31 December 2022. The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative \ufb01nancial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash \ufb02ows of \ufb01nancial liabilities based on the earliest date on which the Group can be required to pay. Note 18. Financial instruments continued Foreign currency risk continued Weighted average effective interest rate Less than 1 month $m 1\u20133 months $m 3 months to 1 year $m 1\u20135 years $m 5+ years $m Total $m 31 December 2022 Non-interest bearing n/a 93.5 \u2013 26.3 47.0 \u2013 166.8 Lease liabilities 7.1% 27.3 57.1 225.2 746.3 10.5 1,066.4 Fixed interest rate instruments 9.7% Principal repayments \u2013 \u2013 100.0 2,400.0 \u2013 2,500.0 Interest charge \u2013 28.0 197.0 464.0 \u2013 689.0 Total 120.8 85.1 548.5 3,657.3 10.5 4,422.2 Weighted average effective interest rate Less than 1 month $m 1\u20133 months $m 3 months to 1 year $m 1\u20135 years $m 5+ years $m Total $m 31 December 2021 Non-interest bearing n/a 71.9 18.6 26.0 71.3 5.7 193.5 Lease liabilities 7.1% 44.4 52.7 217.2 950.3 16.4 1,281.0 Fixed interest rate instruments 9.7% Principal repayments \u2013 \u2013 100.0 2,500.0 \u2013 2,600.0 Interest charge \u2013 28.0 207.0 689.0 \u2013 924.0 Total 116.3 99.3 550.2 4,210.6 22.1 4,998.5 ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-416": {
"value": "Fair values of \ufb01nancial assets and liabilities With the exception of the 2026 Notes and the 2025 Notes, the Group considers the carrying value of all its \ufb01nancial assets and liabilities to be materially the same as their fair value. The fair value of the 2026 Notes and 2025 Notes as determined using market value at 31 December 2022, was $1,364.8 million (2021: $1,814.2 million) and $490.0 million (2021: $661.0 million) respectively. These are compared to their carrying value of $1,680.0 million (2021: $1,776.7 million) and $792.9 million (2021: $792.1 million). The 2026 Notes and the 2025 Notes are categorised as level 1 in the fair value hierarchy. The Group has no material \ufb01nancial assets that are past due. No material \ufb01nancial assets are impaired at the balance sheet date. All \ufb01nancial assets and liabilities with the exception of derivatives are measured at amortised cost. Fair values of derivative instruments All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash \ufb02ow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm\u2019s-length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved. The Group\u2019s derivative carrying and fair values were as follows: Assets/liabilities 2022 Less than 1 year $m 2022 1\u20133 years $m 2022 Total $m 2021 Less than 1 year $m 2021 1\u20133 years $m 2021 Total $m Cash \ufb02ow hedges Oil derivatives (162.1) (49.7) (211.8) (56.7) (66.5) (123.2) (162.1) (49.7) (211.8) (56.7) (66.5) (123.2) Deferred premium Oil derivatives (24.2) (8.2) (32.4) (24.3) (32.4) (56.7) (24.3) (32.4) (56.7) Total assets \u2013 \u2013 \u2013 \u2013 \u2013 \u2013 Total liabilities (186.3) (57.9) (244.2) (81.0) (98.9) (179.9) Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide. The following provides an analysis of the Group\u2019s \ufb01nancial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable: Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities; Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data. All the Group\u2019s derivatives are Level 2 (2021: Level 2). There were no transfers between fair value levels during the year. For \ufb01nancial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by re-assessing categorisation (based on the lowest-level input which is signi\ufb01cant to the fair value measurement as a whole) at the end of each reporting period. ",
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"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-417": {
"value": "Offsetting of \ufb01nancial instruments Financial assets and liabilities are offset and the net amount is reported in the Group balance sheet when there is a legally enforceable right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously. No material enforceable master netting agreements were identi\ufb01ed. The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts recognised for \ufb01nancial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the Group balance sheet. 31 December 2022 Gross amounts recognised $m Gross amounts offset in Group balance sheet $m Net amounts presented in Group balance sheet $m Derivative assets \u2013 \u2013 \u2013 Derivative liabilities (244.2) \u2013 (244.2) 31 December 2021 Gross amounts recognised $m Gross amounts offset in Group balance sheet $m Net amounts presented in Group balance sheet $m Derivative assets 0.2 (0.2) \u2013 Derivative liabilities (180.1) 0.2 (179.9) ",
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"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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},
"fact-418": {
"value": "Commodity price risk The Group uses a number of derivatives to mitigate the commodity price risk associated with its underlying oil revenue. Such commodity derivatives tend to be priced using benchmarks, such as Dated Brent, which correlate as far as possible to the underlying oil revenue. There is an economic relationship between the hedged items and the hedging instruments due to a common underlying, i.e. Dated Brent, between them. Forecast oil sales, which are based on Dated Brent, are hedged with options which have Dated Brent as reference price. An increase in Dated Brent will cause the value of the hedged item and hedging instrument to move in opposite directions. The Group has established a hedge ratio of 1:1 for the hedging relationships as the underlying risk of the commodity derivatives is identical to the hedged risk components. To test the hedge effectiveness, the Group uses the hypothetical derivative method and compares the changes in the fair value of the hedging instruments against the changes in fair value of the hedged items attributable to the hedged risks. The Group hedges its estimated oil revenues on a portfolio basis, aggregating its oil revenues from substantially all of its African oil interests. As at 31 December 2022 and 31 December 2021, all of the Group\u2019s oil derivatives have been designated as cash \ufb02ow hedges. The Group\u2019s oil hedges have been assessed to be highly effective. Financial risk management is adopted centrally for the Group. The Group adopts a risk component hedging strategy. This results from designating the variability in all the cash \ufb02ows attributable to the change in the benchmark price per the oil sales contracts where the critical terms of the hedged item and hedging instrument match. The following table demonstrates the timing, volumes and average \ufb02oor price protected for the Group\u2019s commodity hedges: Hedging position as at 31 December 2022 2023 2024 Oil volume (bopd) 33,095 11,305 Average \ufb02oor price protected ($/bbl) 55.0 55.0 Hedging position as at 31 December 2021 2022 2022 Oil volume (bopd) 42,462 33,095 Average \ufb02oor price protected ($/bbl) 51.37 55.00 The following table demonstrates the hedge position as at 31 December 2022: 2023 hedge position at 31 December 2022 Bopd Bought put (\ufb02oor) Sold call Bought call Hedge structure Collars 33,095 $55.00 $74.62 \u2013 Zero cost dollars \u2013 \u2013 \u2013 \u2013 Straight Puts \u2013 \u2013 \u2013 \u2013 Total/weighted average 33,095 $55.00 $74.62 \u2013 2024 hedge position at 31 December 2022 Bopd Bought put (\ufb02oor) Sold call Bought call Hedge structure Collars 11,305 $55.00 $74.63 \u2013 Total/weighted average 11,305 $55.00 $74.63 \u2013 The following table demonstrates the sensitivity of the Group\u2019s derivative \ufb01nancial instruments to reasonably possible movements in Dated Brent oil prices: Effect on equity Market movement as at 31 Dec 2022 2022 $m 2021 $m Brent oil price 25% (464.4) (416.2) Brent oil price (25%) \u2013 41.1 The following assumptions have been used in calculating the sensitivity in movement of the oil price: the pricing adjustments relate only to the point forward mark-to-market (MTM) valuations, the price sensitivities assume there is no ineffectiveness related to the oil hedges and the sensitivities have been run only on the intrinsic element of the hedge as Management considers this to be the material component of oil hedge valuations. Hedge reserve summary The hedge reserve represents the portion of deferred gains and losses on hedging instruments deemed to be effective cash \ufb02ow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the cash \ufb02ow hedge reserve by intrinsic and time value, net of tax effects: Cash \ufb02ow hedge reserve 2022 $m 2021 $m Oil derivatives \u2013 intrinsic (150.3) (39.5) Oil derivatives \u2013 time value (94.4) (146.7) The deferred gains and losses in the hedge reserve are subsequently transferred to the income statement at maturity of derivative contracts. The tables below show the impact on the hedge reserve and on sales revenue during the year: Deferred amounts in the hedge reserve \u2013 intrinsic 2022 $m 2021 $m At 1 January (39.3) 4.8 Reclassi\ufb01cation adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 288.5 112.3 Revaluation (losses)/gains arising in the year (399.5) (159.1) Movement in current and deferred tax \u2013 2.7 (110.8) (44.3) At 31 December (150.3) (39.3) ",
"dimensions": {
"concept": "tullowoilplc:DisclosureOfCommodityPriceRisk",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-419": {
"value": "Hedge reserve summary Deferred amounts in the hedge reserve \u2013 time value 2022 $m 2021 $m At 1 January (146.9) (5.4) Reclassi\ufb01cation adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 30.8 40.7 Revaluation losses arising in the year 21.7 (182.3) Movement in current and deferred tax \u2013 0.1 52.5 (141.5) At 31 December (94.4) (146.9) Reconciliation to sales revenue 2022 $m 2021 $m Oil derivatives \u2013 transferred to sales revenue 288.5 112.3 Deferred premium paid 30.8 40.7 Net losses/(gain) from commodity derivatives in sales revenue (note 2) 319.3 153.0 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDetailedInformationAboutHedgingInstrumentsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-420": {
"value": "Interest rate risk Interest rate risk is the risk that the fair value of future cash \ufb02ows of a \ufb01nancial instrument will \ufb02uctuate because of changes in market interest rates. During part of the \ufb01nancial year 2021, the Group was exposed to interest rate risk as it borrowed funds at both \ufb01xed and \ufb02oating interest rates. Following the debt re\ufb01nancing in May 2021, all of the Group\u2019s borrowings are \ufb01xed interest bearing. The Super Senior Revolving Credit Facility is based on \ufb02oating interest rates and remains undrawn as at 31 December 2022. Fixed rate debt comprises 2025 Notes and 2026 Notes. The interest rate pro\ufb01le of the Group\u2019s \ufb01nancial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2022 and 2021, was as follows: 2022 Cash and cash equivalents $m 2022 Fixed rate debt $m 2022 Total $m 2021 Cash and cash equivalents $m 2021 Fixed rate debt $m 2021 Total $m US$ 578.1 (2,500.0) (1,921.9) 376.2 (2,600.0) (2,223.8) Euro 0.3 \u2013 0.3 1.3 \u2013 1.3 Sterling 16.3 \u2013 16.3 85.4 \u2013 85.4 XAF 38.8 \u2013 38.8 \u2013 \u2013 Other 2.8 \u2013 2.8 6.2 \u2013 6.2 636.3 (2,500.0) (1,863.7) 469.1 (2,600.0) (2,130.9) Cash and cash equivalents consisted of $230.7 million (2021: $159.9 million) of deposits which earn interest at rates set in advance for periods ranging from overnight to three months by reference to market rates. The sensitivity of the Group\u2019s \ufb01nancial instruments to reasonably possible movements in interest rates is considered not material. ",
"dimensions": {
"concept": "tullowoilplc:DisclosureOfInterestRateRisk",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-421": {
"value": "Credit risk The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and speci\ufb01c transaction approvals. The Group limits its counterparty credit risk on cash and cash equivalent balances by dealing only with \ufb01nancial institutions with credit ratings of at least A or equivalent. The primary credit exposures for the Group are its receivables generated by the marketing of crude oil and amounts due from JV Partners (including in relation to their share of the TEN FPSO lease). These exposures are managed at the corporate level. The Group\u2019s crude sales are predominantly made to international oil market participants including the oil majors, trading houses and re\ufb01neries. JV Partners are predominantly international major oil and gas market participants. Counterparty evaluations are conducted utilising international credit rating agency and \ufb01nancial assessments. Where considered appropriate, security in the form of trade \ufb01nance instruments from \ufb01nancial institutions with an appropriate credit rating, such as letters of credit, guarantees and credit insurance, are obtained to mitigate the risks. The Group generally enters into derivative agreements with banks which are lenders under the SSRCF. The Group does not have any signi\ufb01cant credit risk exposure to any single counterparty or any group of counterparties. The maximum \ufb01nancial exposure due to credit risk on the Group\u2019s \ufb01nancial assets, representing the sum of cash and cash equivalents, investments, derivative assets, trade receivables, and receivables from Joint Venture Partners, as at 31 December 2022 was $1,438.7 million (2021: $1,609.6 million). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCreditRiskExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-422": {
"value": "Foreign currency risk The Group conducts and manages its business predominantly in US dollars, the functional currency of the industry in which it operates. The Group also purchases the functional currencies of the countries in which it operates routinely on the spot market. From time to time the Group undertakes transactions denominated in other currencies arising from certain operating and capital expenditure incurred in currencies other than US dollars; these exposures are often managed by executing foreign currency \ufb01nancial derivatives. There were no foreign currency \ufb01nancial derivatives in place as at 31 December 2022 (2021: nil). Cash balances are held in other currencies to meet immediate operating and administrative expenses or to comply with local currency regulations. As at 31 December 2022, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $58.1 million in non-US dollar-denominated cash and cash equivalents (2021: $46.9 million). The following table demonstrates the sensitivity of the Group\u2019s \ufb01nancial instruments to reasonably possible movements in US dollar exchange rates: Effect on pro\ufb01t before tax Effect on equity Market movement 2022 $m 2021 $m 2022 $m 2021 $m US$/foreign currency exchange rates 20% 9.7 (7.8) 9.7 (7.8) US$/foreign currency exchange rates (20%) (14.5) 11.7 (14.7) 11.7 Liquidity risk The Group manages its liquidity risk using both short-term and long-term cash \ufb02ow projections, supplemented by debt \ufb01nancing plans and active portfolio management across the Group. Ultimate responsibility for liquidity risk management rests with the Board of Directors, which has established an appropriate liquidity risk management framework covering the Group\u2019s short, medium and long-term funding and liquidity management requirements. The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group\u2019s producing assets and delays to development projects. The Group had $1.1 billion (2021: $0.9 billion) of total facility headroom and free cash as at 31 December 2022. The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative \ufb01nancial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash \ufb02ows of \ufb01nancial liabilities based on the earliest date on which the Group can be required to pay. Foreign currency risk continued Weighted average effective interest rate Less than 1 month $m 1\u20133 months $m 3 months to 1 year $m 1\u20135 years $m 5+ years $m Total $m 31 December 2022 Non-interest bearing n/a 93.5 \u2013 26.3 47.0 \u2013 166.8 Lease liabilities 7.1% 27.3 57.1 225.2 746.3 10.5 1,066.4 Fixed interest rate instruments 9.7% Principal repayments \u2013 \u2013 100.0 2,400.0 \u2013 2,500.0 Interest charge \u2013 28.0 197.0 464.0 \u2013 689.0 Total 120.8 85.1 548.5 3,657.3 10.5 4,422.2 Weighted average effective interest rate Less than 1 month $m 1\u20133 months $m 3 months to 1 year $m 1\u20135 years $m 5+ years $m Total $m 31 December 2021 Non-interest bearing n/a 71.9 18.6 26.0 71.3 5.7 193.5 Lease liabilities 7.1% 44.4 52.7 217.2 950.3 16.4 1,281.0 Fixed interest rate instruments 9.7% Principal repayments \u2013 \u2013 100.0 2,500.0 \u2013 2,600.0 Interest charge \u2013 28.0 207.0 689.0 \u2013 924.0 Total 116.3 99.3 550.2 4,210.6 22.1 4,998.5 ",
"dimensions": {
"concept": "tullowoilplc:DisclosureOfForeignCurrencyRisk",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-397": {
"value": "Note 19. Leases This note provides information for leases where the Group is a lessee. The Group did not enter into any contracts acting as a lessor. i) Amounts recognised in the balance sheet Right-of-use assets Lease liabilities Right-of-use assets (included within property, plant and equipment) and lease liabilities 31 December 2022 $m 31 December 2021 $m 31 December 2022 $m 31 December 2021 $m Property leases 39.2 34.8 34.6 41.0 Oil and gas production and support equipment leases 639.0 599.2 942.4 1,107.3 Transportation equipment leases 3.4 6.9 7.1 15.1 Total 681.6 640.9 984.1 1,163.4 Current 251.2 251.5 Non-current 732.9 911.9 Total 984.1 1,163.4 Additions to the right-of-use assets during the 2022 \ufb01nancial year were $63.5 million. Refer to note 10. For ageing of lease liabilities, refer to note 18. The Group\u2019s leases balance includes TEN FPSO, classi\ufb01ed as Oil and gas production and support equipment. As at 31 December 2022, the present value of the TEN FPSO right-of-use asset was $596.9 million (2021: $561.6 million). The increase during the year is due to additional interest in the FPSO following Ghana pre-emption, offset by the depreciation charge. The present value of the TEN FPSO gross lease liability was $847.9 million (2021: $1,012.8 million). A receivable from the Joint Venture Partners of $330.1 million (2021: $478.8 million) was recognised in other assets (note 11) to re\ufb02ect the value of future payments that will be met by cash calls from partners relating to the TEN FPSO lease. The present value of the receivable from the Joint Venture Partners unwinds over the expected life of the lease and the unwinding of the discount is reported within \ufb01nance income. Following discussions with the Joint Venture Partners, Tullow remeasured the Espoir FPSO lease liability to align the accounting with the plan of the partnership to exercise the option to purchase the FPSO in March 2023 for a gross consideration of $20.0 million ($4.7 million net). This resulted in a decrease in the lease liability as at 31 December 2022 to $6.6 million (2021: $13.2 million), and the in right of use asset to $nil (2021: $3.6 million) resulting in a gain on the lease remeasurement of $3.1 million recorded as Other gains and losses in the income statement. Note 19. Leases continued i) Amounts recognised in the balance sheet continued On 2 April 2021, the Group contracted Maersk Venturer offshore drilling rig to undertake the drilling work programme for Jubilee and TEN \ufb01elds in Ghana. As at 31 December 2022, Tullow carries right-of-use assets of $31.2 million (2021: $25.8 million), and gross lease liability of $64.9 million (2021: $59.9 million) as Tullow entered the lease on behalf of the Joint Venture. A receivable from Joint Venture Partners of $32.0 million (2021: $33.0 million) has been recognised in other assets to re\ufb02ect the value of future payments that will be met by cash calls from the Joint Venture Partners. The lease was initially recognised for an 18-month term, in line with the early termination option included in the contract and approvals received by the partners. In July 2022 the contract was extended for a 12-month term ending September 2023. Carrying amounts of the lease liabilities and joint venture leases receivables and the movements during the period: Lease liabilities $m Joint Venture lease receivables $m Total $m At 1 January 2021 (1,216.5) 541.0 (675.5) Additions and changes in lease estimates (161.9) 93.7 (68.2) Payments/ (receipts) 298.3 (142.4) 155.9 Interest (expense)/income (83.3) 38.7 (44.6) At 1 January 2022 (1,163.4) 531.0 (632.4) Additions and changes in lease estimates (89.4) 40.2 (49.2) Acquisitions1 \u2013 (86.6) (86.6) Payments/ (receipts) 342.0 (138.2) 203.8 Interest (expense)/income (76.4) 29.6 (46.8) Currency translation adjustments 3.1 \u2013 3.2 At 31 December 2022 984.1 376.1 608.0 1. This relates to an acquisition through business combination discussed in Note 15. ii) Amounts recognised in the statement of pro\ufb01t or loss Right-of-use assets (included within Property, plant and equipment) 31 December 2022 $m 31 December 2021 $m Depreciation charge of right-of-use assets Property leases 14.0 7.8 Oil and gas production and support equipment leases 46.9 52.8 Total 60.9 60.6 Interest expense on lease liabilities (included in \ufb01nance cost) 76.4 83.4 Interest income on amounts due from Joint Venture Partners (29.6) (38.8) Expense relating to short-term leases 2.0 7.8 Expense relating to leases of low-value assets 1.8 1.0 Total 111.5 114.0 The total net cash out\ufb02ow for leases in 2022 was $203.8 million (2021: $155.9 million). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLeasesExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-398": {
"value": "Note 20. Provisions Notes Decommissioning 2022 $m Other provisions 2022 $m Total 2022 $m Decommissioning 2021 $m Other provisions 2021 $m Total 2021 $m At 1 January 498.7 228.8 727.5 696.1 154.6 850.7 New provisions, changes in estimates and reclassi\ufb01cations (47.6) (19.7) (67.3) (134.8) 90.0 (44.8) Acquisitions1 15 24.8 36.8 61.6 \u2013 \u2013 \u2013 Payments (72.1) (127.3) (199.4) (69.3) (15.7) (85.0) Unwinding of discount 5 6.0 \u2013 6.0 7.6 \u2013 7.6 Currency translation adjustment (11.6) (2.3) (13.9) (0.9) (0.1) (1.0) At 31 December 398.1 116.3 514.4 498.7 228.8 727.5 Current provisions 87.7 11.1 98.8 101.2 195.3 296.5 Non-current provisions 310.4 105.2 415.6 397.5 33.5 431.0 1. This relates to an acquisition through business combination discussed in note 15. Other provisions include non-income tax provisions of $68.3 million (2021: $52.8 million) and $48.0 million (2021: $176.0 million) of disputed cases and claims. Management estimates non-current other provisions would fall due between two and \ufb01ve years. Non-Current other provisions mainly relates to Bangladesh litigation. Refer to Uncertain Tax Treatments in Accounting Policies. This also includes a provision relating to a potential claim arising out of historical contractual agreement. Further information is not provided as it will be seriously prejudicial to the Company\u2019s interest. On 15 February 2022, an arbitration panel delivered an award against Tullow in respect to a historic contractual dispute in Norway related to the acquisition of Spring Energy Norway AS (Spring) from HiTecVision V (HiTec). The Tribunal decided by way of split decision that conditions under the Spring SPA in respect of the bonus payment had been met. The Tribunal ruled that Tullow should pay $76 million to HiTec (an amount which includes interest and costs) and a further amount of $0.7 million in respect of Tribunal costs. This balance was provided for as at 31 December 2021 and was settled in March 2022. The decommissioning provision represents the present value of decommissioning costs relating to the European and African oil and gas interests. The Group has assumed cessation of production as the estimated timing for out\ufb02ow of expenditure. However expenditure could be incurred prior to cessation of production or after and actual timing will depend on a number of factors including, underlying cost environment, availability of equipment and services and allocation of capital. In 2022, the Group has increased the decommissioning discount rate by 1.5-2% from 31 December 2021 due to movement in the risk-free rate. This resulted in a decrease of the provision by $39.5 million in Ghana, $15.6 million in C\u00f4te d\u2019Ivoire and $12.1 million in Gabon. In\ufb02ation assumption1 Discount rate assumption 2022 Cessation of production assumption 2022 Total 2022 $m Discount rate assumption 2021 Cessation of production 2021 Total 2021 $m C\u00f4te d\u2019Ivoire 2% 3.5% 2035 45.6 1.5% 2033 61.7 Gabon 2% 3.5% 2025-2037 49.2 1.5-2% 2026-2036 61.9 Ghana 2% 3.5% 2036 190.2 1.5-2% 2035-2036 193.3 Mauritania n/a n/a 2018 56.0 n/a 2018 61.6 UK n/a n/a 2018 57.1 n/a 2018 120.2 398.1 498.7 1. Short term in\ufb02ation rate assumption has increased from 2% to 4.7% in 2023 and to 2.5% in 2024. Medium and long-term rates of 2% remained unchanged from 31 December 2021. The Group's decommissioning activities are ongoing in the UK and Mauritania and majority of the future costs is expected to be incurred in 2023 ($87.4 million). The remaining activities are planned to continue through to 2027, with an associated expenditure of $25.7 million. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfProvisionsExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-399": {
"value": "Note 21. Deferred taxation Accelerated tax depreciation $m Decommissioning $m Tax losses $m Other temporary differences $m Provision for onerous service contracts $m Deferred petroleum revenue tax $m Total $m At 1 January 2021 (645.7) 105.6 335.7 (8.4) 21.7 12.1 (179.0) Credit/(charge) to income statement 46.8 (16.5) (113.8) (58.7) \u2013 (2.7) (144.9) Transfer to disposals 0.6 (0.2) \u2013 0.7 \u2013 \u2013 1.1 Exchange differences \u2013 (0.1) \u2013 \u2013 \u2013 \u2013 (0.1) At 1 January 2022 (598.3) 88.8 221.9 (66.4) 21.7 9.4 (322.9) Credit/(charge) to income statement 184.0 (22.9) (186.1) (32.6) (5.9) (5.0) (68.5) Acquired through business combination (note 15) (143.6) \u2013 \u2013 \u2013 \u2013 \u2013 (143.6) Exchange differences (0.2) \u2013 \u2013 \u2013 \u2013 (1.8) (2.0) At 31 December 2022 (558.1) 65.9 35.8 (99.0) 15.8 2.6 (537.0) 2022 $m 2021 $m Deferred tax liabilities (551.5) (677.3) Deferred tax assets 14.5 354.4 (537.0) (322.9) The majority of the Group's deferred tax assets and liabilities are expected to be recovered over more than one year. Deferred tax assets are recognised only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse, and a judgement as to whether or not there will be sufficient taxable pro\ufb01ts available to offset the tax assets when they do reverse. This requires assumptions regarding future pro\ufb01tability and is therefore inherently uncertain. To the extent assumptions regarding future pro\ufb01tability change, there can be an increase or decrease in the level of deferred tax assets recognised which can result in a charge or credit in the period in which the change occurs. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-423": {
"value": "Note 22. Called-up equity share capital and share premium account Allotted equity share capital and share premium Equity share capital allotted and fully paid Share premium Number $m $m Ordinary shares of 10p each At 1 January 2021 1,414,071,777 211.7 1,294.7 Issued during the year Exercise of share options 18,008,320 2.5 \u2013 At 1 January 2022 1,432,080,097 214.2 1,294.7 Issued during the year Exercise of share options 7,525,898 1.0 \u2013 At 31 December 2022 1,439,605,995 215.2 1,294.7 The Company does not have a maximum authorised share capital. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-400": {
"value": "Note 22. Called-up equity share capital and share premium account Allotted equity share capital and share premium Equity share capital allotted and fully paid Share premium Number $m $m Ordinary shares of 10p each At 1 January 2021 1,414,071,777 211.7 1,294.7 Issued during the year Exercise of share options 18,008,320 2.5 \u2013 At 1 January 2022 1,432,080,097 214.2 1,294.7 Issued during the year Exercise of share options 7,525,898 1.0 \u2013 At 31 December 2022 1,439,605,995 215.2 1,294.7 The Company does not have a maximum authorised share capital. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:2138003EYHWO75RKS857",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-401": {
"value": "Note 23. Share-based payments Analysis of share-based payment charge Notes 2022 $m 2021 $m Tullow Incentive Plan 3.9 8.1 Employee Share Award Plan 1.2 3.0 2022 PDME Buyout Award 0.5 0.5 2021 Tullow Sharesave Plan 0.2 \u2013 5.8 11.6 Expensed to operating costs 4 0.4 0.5 Expensed as administrative cost 4 5.4 11.1 Total share-based payment charge 5.8 11.6 The national insurance liability as at 31 December 2022 was $1.6 million (2021:$1.3 million) Tullow Incentive Plan (TIP) Under the TIP, Senior Management can be granted nil exercise price options, normally exercisable from three years (\ufb01ve years in the case of the Company\u2019s Directors) to ten years following grant provided an individual remains in employment. The size of awards depends on both annual performance measures and total shareholder return (TSR) over a period of up to three years. There are no post-grant performance conditions. No dividends are paid over the vesting period; however, it has been agreed for the TIP Awards since 2018 that an amount equivalent to the dividends that would have been paid on the TIP shares during the vesting period if they were \u2018real\u2019 shares will also be payable on exercise of the award. There are further details of the TIP in the Remuneration Report on pages 73 to 97. The weighted average remaining contractual life for TIP awards outstanding at 31 December 2022 was 4.9 years. Employee Share Award Plan (ESAP) Most Group employees are eligible to be granted nil exercise price options, that are exercisable from three to ten years following grant. An individual must normally remain in employment for three years from grant for the share to vest. Awards are not subject to post-grant performance conditions. No dividends are paid over the vesting period; however, it has been agreed for the ESAP awards granted since 2018 it was agreed that an amount equivalent to the dividends that would have been paid on the ESAP shares during the vesting period if they were \u2018real\u2019 shares will also be payable on exercise of the award. Phantom options that provide a cash bonus equivalent to the gain that could be made from a share option (being granted over a notional number of shares) have also been granted under the ESAP in situations where the grant of share options was not practicable. The weighted average remaining contractual life for ESAP awards outstanding at 31 December 2022 was 6.7 years. 2010 Share Option Plan (2010 SOP) Participation in the 2010 SOP was available to most of the Group\u2019s employees. Options have an exercise price equal to market value shortly before grant and are normally exercisable between three and ten years from the date of the grant subject to continuing employment. Phantom options, providing a cash bonus equivalent to the gain that could be made from a share option, have also been granted under the 2010 SOP in situations where the grant of share options was not practicable. Outstanding options under the SOP at 31 December 2022 had exercise prices of 900p to 1,039p (2021: 900p to 1,294p) and remaining contractual lives between 53 days and 219 days. The weighted average remaining contractual life is 0.3 years. 2020 PDMR Buyout Awards On 5 August 2020, the Company granted the new Chief Executive Officer a number of Buyout Awards following the commencement of their employment in order to compensate them for certain share arrangements forfeited upon leaving their former employer. The grant of the awards was conditional on the CEO purchasing shares in the Company with a value of \u00a3350,000 (the \u2018Purchased Shares\u2019). These awards will vest after \ufb01ve years from the date of joining subject to continued service and the retention of the Purchased Shares. The awards comprise: a restricted share award in the form of a nil-cost option over 3,000,000 shares; a share option over 3,000,000 shares with a per share exercise price of \u00a30.2566 (being equal to the market value of a share at the close of trading on the dealing date immediately following the date on which the Purchased Shares were acquired); and a share option over 3,000,000 shares with a per share exercise price of \u00a30.5132 (being twice the exercise price for the above options). The awards will ordinarily vest on 1 July 2025 and if they remain unexercised will expire on 1 July 2030. There are further details of the 2020 PDMR Buyout Awards in the Remuneration Report on pages 73 to 97. The weighted average remaining contractual life for the PDMR Buyout Awards outstanding at 31 December 2022 was 7.5 years. Note 23. Share-based payments continued 2021 Tullow Sharesave Plan (SAYE) UK based employees are eligible to participate in the SAYE scheme introduced in 2021. These are standard statutory HMRC approved \u2018Save as you earn\u2019 awards. To participate in the SAYE, employees choose how much money of their net salary to save each month (subject to certain limits) for a period of three years. At the end of the period employees are entitled to purchase share using the funds they have saved at a price 20% below the market price on the day before the invitation date. Alternatively, they can elect to take back all their savings as cash. Only employees who remain in service and continue to pay monthly contributions will be eligible to purchase shares. If they leave employment or choose to stop paying contributions before the end of the three-year period they will be refunded the amount they have saved. Outstanding SAYE awards at 31 December 2022 had exercise prices of 38p to 40p and remaining contractual lives between 2.4 years and 3.4 years. The weighted average remaining contractual life is 2.8 years. UK and Irish Share Incentive Plans (SIPs) These are all-employee plans set up in the UK and Ireland, to enable employees to save out of salary up to prescribed monthly limits. Contributions are used by the SIP trustees to buy Tullow shares (Partnership Shares) at the end of each three-month accumulation period. The Company makes a matching contribution to acquire Tullow shares (Matching Shares) on a one-for-one basis. Under the UK SIP, Matching Shares are subject to time-based forfeiture over three years on leaving employment in certain circumstances or if the related Partnership Shares are sold. The fair value of a Matching Share is its market value when it is awarded. Under the UK SIP: (i) Partnership Shares are purchased at the lower of their market values at the start of the accumulation period and the purchase date (which is treated as a three-month share option for IFRS 2 purposes and therefore results in an accounting charge); and (ii) Matching Shares vest over the three years after being awarded (resulting in their accounting charge being spread over that period). Under the Irish SIP: (i) Partnership Shares are bought at the market value at the purchase date (which does not result in any accounting charge); and (ii) Matching Shares vest over the two years after being awarded (resulting in their accounting charge being spread over that period). The following table illustrates the number and average weighted share price at grant or weighted average exercise price (WAEP) of, and movements in, share options under the TIP, ESAP, 2010 SOP, 2020 buyout and SAYE. Outstanding as at 1 January Granted during the year Exercised during the year Forfeited/ expired during the year Outstanding at 31 December Exercisable at 31 December 2022 TIP \u2013 number of shares 21,740,803 8,076,264 4,529,667 433,152 24,854,248 3,014,253 2022 TIP \u2013 average weighted share price at grant 105.3 49.1 211.6 64.4 68.4 220.0 2021 TIP \u2013 number of shares 28,116,828 2,488,749 8,191,155 673,619 21,740,803 2,054,238 2021 TIP \u2013 average weighted share price at grant 133.0 60.5 188.8 81.8 105.3 191.2 2022 ESAP \u2013 number of shares 17,638,898 3,556,316 2,803,974 1,061,163 17,330,077 4,613,422 2022 ESAP \u2013 average weighted share price at grant 96.5 49.3 180.0 45.2 76.4 228.5 2021 ESAP \u2013 number of shares 29,919,699 \u2013 9,462,175 2,818,626 17,638,898 5,181,246 2021 ESAP \u2013 average weighted share price at grant 126.1 \u2013 198.4 67.8 96.5 213.4 2022 SOP \u2013 number of shares 2,046,755 \u2013 \u2013 1,868,472 178,283 178,283 2022 SOP \u2013 WAEP 1,106.0 \u2013 \u2013 1,118.4 976.4 976.4 2021 SOP \u2013 number of shares 5,943,263 \u2013 \u2013 3,896,508 2,046,755 2,046,755 2021 SOP \u2013 WAEP 1,124.6 \u2013 \u2013 1,134.4 1,106.0 1,106.0 2022 Buyout Awards \u2013 number of shares 9,000,000 \u2013 \u2013 \u2013 9,000,000 \u2013 2022 Buyout Awards \u2013 WAEP 25.7 \u2013 \u2013 \u2013 25.7 \u2013 2021 Buyout Awards \u2013 number of shares 9,000,000 \u2013 \u2013 \u2013 9,000,000 \u2013 2021 Buyout Awards \u2013 WAEP 25.7 \u2013 \u2013 \u2013 25.7 \u2013 2022 SAYE \u2013 number of options 1,534,241 975,600 \u2013 121,970 2,387,871 \u2013 2022 SAYE \u2013 WAEP 38.0 40.0 \u2013 38.2 38.8 \u2013 2021 SAYE \u2013 number of options \u2013 1,534,241 \u2013 \u2013 1,534,241 \u2013 2021 SAYE \u2013 WAEP \u2013 38.0 \u2013 \u2013 38.0 \u2013 The options granted during the year were valued using a proprietary binomial valuation. Note 23. Share-based payments continued The following table details the weighted average fair value of awards granted and the assumptions used in the fair value expense calculations. 2022 ESAP 2022 TIP 2021 TIP 2022 SAYE 2021 SAYE Weighted average fair value of awards granted 49.3p 49.1p 60.5p 23.1p 34.8p Principal inputs to options valuations model: Weighted average share price at grant 49.3p 49.1p 60.5p 38.4p 53.6p Weighted average exercise price 0.0p 0.0p 0.0p 40.0p 38.0p Risk-free interest rate per annum1 1.5% to 4.4% 1.5%/1.5% 0.1%/0.4% 4.3% 0.7% Expected volatility per annum1, 2 101% to 102% 102%/85% 101%/85% 91% 92% Expected award life (years) 1, 3 3.0 3.0/5.0 3.0/5.0 3.6 3.6 Dividend yield per annum 4 n/a n/a n/a 0.0% 0.0% Employee turnover before vesting per annum1 5% 5%/0% 5%/0% 5% 5% 1. Shows the assumption for 2022 and 2021 TIP awards made to Senior Management/Executives and Directors respectively. 2. Expected volatility was determined by calculating the historical volatility of the Company\u2019s share price over a period commensurate with the expected life of the awards. The fair values of the 2022 ESAP and TIP Awards, and the 2021 TIP Awards are not affected by the assumption for the Company\u2019s share price volatility. 3. The expected life is the average expected period from date of grant to exercise allowing for the Company\u2019s best estimate of participants\u2019 expected exercise behaviour. 4. No dividend yield assumption is needed for the fair value calculations for the 2022 ESAP and TIP Awards as a dividend equivalent will be payable on the exercise of these awards. ",
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"value": "Note 24. Commitments and contingencies 2022 $m 2021 $m Capital commitments 301.2 169.9 Contingent liabilities Performance guarantees 84.1 100.8 Other contingent liabilities 55.8 14.0 139.9 114.8 Where Tullow acts as operator of a Joint Venture the capital commitments reported represent Tullow\u2019s net share of these commitments. Where Tullow is non-operator the value of capital commitments is based on committed future work programmes. Performance guarantees are in respect of abandonment obligations, committed work programmes and certain \ufb01nancial obligations. Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash out\ufb02ow to be higher than remote but not probable. The timing of any economic out\ufb02ow if it were to occur would likely range between one and \ufb01ve years. The movement in capital commitments is predominantly due to certain equipment costs being classi\ufb01ed as capital expenditure following the transition of operatorship to Tullow on the Jubilee FPSO in 2022. These were previously recognised as operating expenses. In addition, Tullow's equity interest increased following Ghana pre-emption. ",
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"value": "Note 24. Commitments and contingencies 2022 $m 2021 $m Capital commitments 301.2 169.9 Contingent liabilities Performance guarantees 84.1 100.8 Other contingent liabilities 55.8 14.0 139.9 114.8 Where Tullow acts as operator of a Joint Venture the capital commitments reported represent Tullow\u2019s net share of these commitments. Where Tullow is non-operator the value of capital commitments is based on committed future work programmes. Performance guarantees are in respect of abandonment obligations, committed work programmes and certain \ufb01nancial obligations. Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash out\ufb02ow to be higher than remote but not probable. The timing of any economic out\ufb02ow if it were to occur would likely range between one and \ufb01ve years. The movement in capital commitments is predominantly due to certain equipment costs being classi\ufb01ed as capital expenditure following the transition of operatorship to Tullow on the Jubilee FPSO in 2022. These were previously recognised as operating expenses. In addition, Tullow's equity interest increased following Ghana pre-emption. ",
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"value": "Note 24. Commitments and contingencies 2022 $m 2021 $m Capital commitments 301.2 169.9 Contingent liabilities Performance guarantees 84.1 100.8 Other contingent liabilities 55.8 14.0 139.9 114.8 Where Tullow acts as operator of a Joint Venture the capital commitments reported represent Tullow\u2019s net share of these commitments. Where Tullow is non-operator the value of capital commitments is based on committed future work programmes. Performance guarantees are in respect of abandonment obligations, committed work programmes and certain \ufb01nancial obligations. Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash out\ufb02ow to be higher than remote but not probable. The timing of any economic out\ufb02ow if it were to occur would likely range between one and \ufb01ve years. The movement in capital commitments is predominantly due to certain equipment costs being classi\ufb01ed as capital expenditure following the transition of operatorship to Tullow on the Jubilee FPSO in 2022. These were previously recognised as operating expenses. In addition, Tullow's equity interest increased following Ghana pre-emption. ",
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"value": "Note 25. Related party transactions The Directors of Tullow Oil plc are considered to be the only Key Management Personnel as de\ufb01ned by IAS 24 Related Party Disclosures. 2022 $m 2021 $m Short term employee bene\ufb01ts 2.5 3.9 Post-employment bene\ufb01ts 0.1 0.3 Share-based payments 1.4 1.8 4.0 6.0 Short-term employee bene\ufb01ts These amounts comprise fees paid to the Directors in respect of salary and bene\ufb01ts earned during the relevant \ufb01nancial year, plus bonuses awarded for the year. Post-employment bene\ufb01ts These amounts comprise amounts paid into the pension schemes of the Directors. Share-based payments This is the cost to the Group of Directors\u2019 participation in share-based payment plans, as measured by the fair value of options and shares granted, accounted for in accordance with IFRS 2 Share-based Payment. There are no other related party transactions. Further details regarding transactions with the Directors of Tullow Oil plc are disclosed in the Remuneration Report on pages 73 to 97. ",
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"value": "26. Climate change and energy transition In March 2021, Tullow announced its commitment to being Net Zero on our Scope 1 and Scope 2 emissions on a net equity basis by 2030 supporting the goal of limiting global temperature rise to well below 2o C as per Article 2 of the Paris Agreement. This note describes how Tullow has considered climate related impacts in some key areas of the \ufb01nancial statements and how this translates into the valuation of assets and measurement of liabilities as Tullow make progress in the energy transition. Note (ag) key sources of estimation uncertainties describes those uncertainties that have the potential to have a material effect on the Group Balance Sheet in the next 12 months. This note describes the key areas of climate impacts that potentially have short and longer-term effects on amounts recognised in the Group Balance Sheet as at 31 December 2022. Where relevant this note contains references to other notes to the Group Financial Statements and aims to provide an overarching summary. Financial planning assumptions Tullow targets being Net Zero scope 1 and 2 emissions by 2030, compared to 2020 levels on a net equity basis, and at least 40% reduction in GHG by 2025 have been included in Tullow\u2019s business plans. The \ufb01nancial statements are based on reasonable and supportable assumptions that represent management\u2019s current best estimate of the range of economic conditions that may exist in the foreseeable future. The Group has performed an assessment of the potential future impact of Climate Change on key elements of its Financial Statements utilising three IEA scenarios (see page 23 for details). Tullow continues to assess the impact to operating cash \ufb02ow (OCF) on our currently producing assets using the oil price assumptions within the IEA scenarios. We focused our assessment on impacts to OCF for our existing production portfolio over 1, 5, and 10 years consistent with our Viability Statement. It is clear from the oil price trajectories in the revised APS and NZE scenarios that the IEA predicts a more challenging oil price environment should the assumptions within these scenarios come to pass. Tullow\u2019s corporate oil price planning assumption is generally higher than the IEA Scenarios, with the exception of the STEPS scenario from 2024 onward. Given the STEPS scenario is a conservative benchmark for future oil prices, re\ufb02ecting global policies and implementing measures adopted as of the end September 2022, we consider our current planning assumptions, informed by a range of broker and consultant forecasts, to be a fair consideration of oil market conditions over the medium term. We also assess acute and chronic physical climate impacts on our existing assets and incorporate meteorological and climate conditions into operational design considerations, with support from external consultant- Verisk Maplecroft in 2019. This process identi\ufb01ed a potential exposure related to consumables stored at Ghana onshore facility, though the related \ufb01nancial impact was deemed insigni\ufb01cant. The physical effects of climate change have also been taken into consideration for core operated asset locations in Ghana, Guyana and Kenya. Analysis suggests exposure to physical risks is relatively minimal in comparison to historical conditions, however there is risk of increasing extremes in cyclical precipitation and drought events onshore Kenya. We will continue to monitor and assess our assets\u2019 exposure to physical climate risks and will evolve our understanding of the potential transmission pathways of climate-related risks and related costs which may affect our operations, strategy or performance including through our supply chain. Similarly, while carbon prices are projected to grow there is low likelihood that a compliance carbon pricing mechanism, such as a carbon tax or emissions trading scheme, will be formalised in our core geographies, and not before Tullow\u2019s Scope 1 and 2 emissions have peaked (before 2025). Tullow reviewed and revised its internal shadow carbon price to $25/tCO2e in line with the NZE carbon price for other emerging market and developing economies, which we see as a robust but realistic carbon price assumption for host nations where we have producing assets. Based on the forecast emissions pro\ufb01le of our portfolio in 2030, the majority of which is from emissions associated with our Ghana production assets, we calculate a potential annual carbon price sensitivity of $12.5 million. To mitigate our residual, hard to abate emissions we are developing a nature based carbon offset project with the Forestry Commission of Ghana. We will have more visibility of the future costs of the project as we progress towards FID in 2023. The carbon price sensitivity or costs for nature based carbon offset projects are not included in the value in use calculation of the recoverable amount of the Group CGUs as these are considered as corporate costs. Pricing assumptions used will continue to be updated for changes in the economic environment and the pace of the energy transition. Tullow will continue to use the \u201cNet Zero Emissions by 2050 Scenario\u201d to assess potential \ufb01nancial impacts to the following: Intangible exploration and evaluation assets The \u201cNet Zero Emissions by 2050 Scenario\u201d represents a challenging oil price environment for future exploration and development investments, particularly post 2030 when the bulk of the cash \ufb02ows would be generated from these types of projects. Therefore, this could result in a potential write-off of all of the $253 million net book value if the assumptions within the NZE scenario were to arise. Property, plant and equipment The Group has included the costs in its impairment assessment directly attributable to CGU\u2019s associated with its Net Zero plans. The \u201cNet Zero Emission by 2050 Scenario\u201d would trigger reductions in cash \ufb02ows of between 0\u201310%. Speci\ufb01cally, if the \u201cNet Zero emission by 2050 scenario\u201d were to arise the Group would recognise an additional impairment of $654 million. As stated above the Group does not expect a material impact on any other balance sheet line item as a result of the IEA scenarios. 26. Climate change and energy transition continued Decommissioning provision The energy transition could result in decommissioning taking place earlier than anticipated. The risk on the timing of decommissioning activities is limited, supported by production plans to fully produce \ufb01elds in the foreseeable future. The discount rate used to discount decommissioning provision is between 10-15-years term in line with the average remaining life of our producing assets. Under the \"Net Zero Emission by 2050 Scenario\" cessation of production assumptions would accelerate by; Ghana 0-7 years, Gabon 0-8 years and C\u00f4te d\u2019Ivoire 7 years. Governmental and societal responses to climate change risks are still developing, and are interdependent upon each other, and consequently \ufb01nancial statements cannot capture all possible future outcomes as these are not yet known.",
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"value": "Note 27. Events since 31 December 2022 Non adjusting events Throughout 2021 and 2022, Tullow has received revised and new tax assessments from the Ghana Revenue Authority (GRA) resulting in a combined potential exposure of c.$1 billion. Tullow believes these assessments are without merit and \ufb01led requests for arbitration with the International Chamber of Commerce in London, in accordance with the dispute resolution process set out in the Petroleum Agreements which govern Tullow Ghana Limited\u2019s activities in Ghana. Notwithstanding this formal step, Tullow intends to continue to engage with the Government of Ghana, including the GRA, with the aim of resolving these disputes on a mutually acceptable basis. In March 2023, Tullow and its JV Partners submitted an updated Field Development Plan to the Ministry of Energy and Petroleum and the Energy and Petroleum Regulatory Commission Authority in Kenya, for their approval. This is currently under review by the relevant authorities. In 2023, there were two new appointments: Richard Miller appointed as Chief Financial Officer (CFO) from January 2023. Roald Goethe appointed as independent non-executive Director from February 2023. There have not been any other events since 31 December 2022 that have resulted in a material impact on the year end results. ",
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"value": "Non adjusting events Throughout 2021 and 2022, Tullow has received revised and new tax assessments from the Ghana Revenue Authority (GRA) resulting in a combined potential exposure of c.$1 billion. Tullow believes these assessments are without merit and \ufb01led requests for arbitration with the International Chamber of Commerce in London, in accordance with the dispute resolution process set out in the Petroleum Agreements which govern Tullow Ghana Limited\u2019s activities in Ghana. Notwithstanding this formal step, Tullow intends to continue to engage with the Government of Ghana, including the GRA, with the aim of resolving these disputes on a mutually acceptable basis. In March 2023, Tullow and its JV Partners submitted an updated Field Development Plan to the Ministry of Energy and Petroleum and the Energy and Petroleum Regulatory Commission Authority in Kenya, for their approval. This is currently under review by the relevant authorities. In 2023, there were two new appointments: Richard Miller appointed as Chief Financial Officer (CFO) from January 2023. Roald Goethe appointed as independent non-executive Director from February 2023. There have not been any other events since 31 December 2022 that have resulted in a material impact on the year end results. ",
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"fact-406": {
"value": "Note 28. Cash \ufb02ow statement reconciliations Purchases of intangible exploration and evaluation assets 2022 $m 2021 $m Additions to intangible exploration and evaluation assets 39.2 46.3 Associated cash \ufb02ows Purchases of intangible exploration and evaluation assets (42.6) (86.1) Non-cash movements/presented in other cash \ufb02ow lines Movement in working capital 3.4 39.8 Purchases of property, plant and equipment 2022 $m 2021 $m Additions to property, plant and equipment 370.7 148.1 Associated cash \ufb02ows Purchases of property, plant and equipment (263.8) (150.4) Non-cash movements/presented in other cash \ufb02ow lines Decommissioning asset revisions 19.9 134.8 Right-of-use asset additions (63.5) (73.5) Movement in working capital (63.3) (59.0) Movement in borrowings 2022 $m 2021 $m 2020 $m 2022 Movement 2021 Movement Borrowings 2,472.8 2,568.7 3,170.5 (95.9) (601.8) Associated cash \ufb02ows Debt arrangement fees \u2013 (56.6) Repayment of borrowings (100.0) (2,379.9) Drawdown of borrowings \u2013 1,800.0 Non-cash movements/presented in other cash \ufb02ow lines Amortisation of arrangement fees and accrued interest 4.1 34.7 ",
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"value": "Note 29. Dividends In 2022, the Board recommended that no interim or \ufb01nal dividend would be paid. ",
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"value": "Note 30. Tullow Oil plc subsidiaries As at 31 December 2022 Each undertaking listed below is a subsidiary by virtue of Tullow Oil plc holding, directly or indirectly, a majority of voting rights in the undertaking. The ownership percentages are equal to the effective equity owned by the Group. Unless otherwise noted, the share capital of each undertaking comprises ordinary shares or the local equivalent thereof. The percentage of equity owned by the Group is 100% unless otherwise noted. The results of all undertakings listed below are fully consolidated in the Group\u2019s Financial Statements. Company name Country of incorporation Direct or indirect Address of registered office Hardman Oil and Gas Pty Ltd\u00b9 Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia Hardman Resources Pty Ltd Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia Tullow Chinguetti Production Pty Ltd Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia Tullow Petroleum (Mauritania) Pty Ltd Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia Tullow Uganda Holdings Pty Ltd\u00b2 Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia Tullow Uganda Operations Pty Ltd Australia Indirect Level 9, 1 William Street, Perth WA 6000, Australia Eagle Drill Limited British Virgin Islands Indirect (50%) Akara Building, 24 De Castro Street, Wickhams Cay, Road Town, Tortola, British Virgin Islands Tullow (EA) Holdings Limited British Virgin Islands Indirect Ritter House, Wickhams Cay, Tortola, VG1110, British Virgin Islands DWT-T Company Cayman Islands Indirect PO Box 32322, 4th Floor Century Yard, Cricket Square, George Town, KY1-1209, Cayman Islands Planet Oil International Limited\u00b3 England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Argentina Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Comoros Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow C\u00f4te d\u2019Ivoire Onshore Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Group Services Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Jamaica Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow New Ventures Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Mozambique Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Oil 100 Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Oil 101 Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Oil Finance Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Oil SK Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Oil SPE Limited England and Wales Direct 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Peru Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Technologies Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Uruguay Limited England and Wales Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Oil Gabon SA Gabon Indirect Quartier Tahiti, Immeuble Narval B.P. 9773, Libreville, Gabon Note 30. Tullow Oil plc subsidiaries continued As at 31 December 2022 continued Company name Country of incorporation Direct or indirect Address of registered office Tullow Gabon Limited Isle of Man Indirect First Names House, Victoria Road, Douglas IM2 4DF, Isle of Man Tullow Oil (Mauritania) Ltd Guernsey Indirect P.O. Box 119, Martello Court, Admiral Park, St. Peter Port GY1 3HB, Guernsey Tullow Oil Holdings (Guernsey) Ltd\u2074 Guernsey Indirect P.O. Box 119, Martello Court, Admiral Park, St. Peter Port GY1 3HB, Guernsey Tullow Oil Limited Ireland Direct Number 1, Central Park, Leopardstown, Dublin 18, Ireland Tullow Congo Limited Isle of Man Indirect First Names House, Victoria Road, Douglas IM2 4DF, Isle of Man Tullow Gabon Holdings Limited Isle of Man Indirect First Names House, Victoria Road, Douglas IM2 4DF, Isle of Man Tullow Mauritania Limited Isle of Man Indirect First Names House, Victoria Road, Douglas IM2 4DF, Isle of Man Tullow Namibia Limited Isle of Man Indirect First Names House, Victoria Road, Douglas IM2 4DF, Isle of Man Tullow Uganda Limited Isle of Man Indirect First Names House, Victoria Road, Douglas IM2 4DF, Isle of Man Tullow C\u00f4te d\u2019Ivoire Exploration Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey Tullow C\u00f4te d\u2019Ivoire Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey Tullow Ghana Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey Tullow India Operations Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey Tullow Oil (Jersey) Limited Jersey Direct 44 Esplanade, St Helier JE4 9WG, Jersey Tullow Oil International Limited Jersey Indirect 44 Esplanade, St Helier JE4 9WG, Jersey Tullow Ethiopia BV Netherlands Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Guyana BV Netherlands Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Hardman Holdings BV Netherlands Indirect Prinses Margrietplantsoen 33, 2595AM \u2018s-Gravenhage, The Netherlands Tullow Kenya BV Netherlands Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Netherlands Holding Cooperatief BA\u2075 Netherlands Indirect Prinses Margrietplantsoen 33, 2595AM \u2019s-Gravenhage, The Netherlands Tullow Overseas Holdings BV Netherlands Direct 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Suriname BV Netherlands Indirect Prinses Margrietplantsoen 33, 2595AM \u2019s-Gravenhage, The Netherlands Tullow Uganda Holdings BV Netherlands Indirect Prinses Margrietplantsoen 33, 2595AM \u2019s-Gravenhage, The Netherlands Tullow Zambia BV Netherlands Indirect 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT, United Kingdom Tullow Oil Norge AS Norway Indirect Tordenskioldsgate 6B, 0160 Oslo, Norway Energy Africa Bredasdorp (Pty) Ltd South Africa Indirect 11th Floor, Convention Tower, Heerengracht Street, Foreshore, Cape Town 8001, South Africa Tullow South Africa (Pty) Limited South Africa Indirect 11th Floor, Convention Tower, Heerengracht Street, Foreshore, Cape Town 8001, South Africa T.U. S.A. Uruguay Indirect Colonia 810, Of. 403, Montevideo, Uruguay 1. Dissolved in October 2022. 2. Dissolved in October 2022. 3. Dissolved in December 2022. 4. Dissolved in March 2022. 5. Dissolved in January 2023. ",
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"value": "Note 31. Licence interests Current exploration, development and production interests Ghana Licence/Unit area Fields Area sq km Tullow interest Operator Other partners Deepwater Tano TEN Development Area 1 Jubilee, Wawa, Tweneboa, Enyenra, Ntomme 619 54.84% Tullow Kosmos, KEGIN, GNPC, Jubilee Oil Holdings, Petro SA West Cape Three Points Jubilee 150 25.66% Tullow Kosmos, KEGIN, GNPC, Jubilee Oil Holdings, Petro SA Jubilee Field Unit Area 2 Jubilee, Mahogany, Teak 38.97% Tullow Kosmos, GNPC, Petro SA 1. GNPC has exercised its right to acquire an additional 5% in TEN. Tullow's interest is 54.84% after successfully pre-empting on Kosmos' purchase of Occidental Petroleum's stake in both assets. 2. A unitisation agreement covering the Jubilee \ufb01eld was agreed by the partners of the West Cape Three Points and the Deepwater Tano licences. The Jubilee Unit Area was expanded in 2017 to include the Mahogany and Teak \ufb01elds. It now includes all of the remaining part of the West Cape Three Points licence and a small part of the Deepwater Tano licence. Non-operated Licence/Unit area Fields Area sq km Tullow interest Operator Other partners C\u00f4te d\u2019Ivoire CI-26 Special Area \u2018E\u2019 Espoir 235 21.33% CNR Petroci Gabon Avouma Avouma, South Tchibala 52 7.50% Vaalco Addax (Sinopec), Sasol, PetroEnergy Ebouri Ebouri 15 7.50% Vaalco Addax (Sinopec), Sasol, PetroEnergy Echira Echira 76 40.00% Perenco Gabon Oil Company Etame Etame, North Tchibala 49 7.50% Vaalco Addax (Sinopec), Sasol, PetroEnergy Ezanga 5,626 8.57% Maurel & Prom Gwedidi Gwedidi 5 7.50% Maurel & Prom Gabon Oil Company Limande Limande 54 40.00% Perenco Gabon Oil Company Mabounda Mabounda 6 7.50% Maurel & Prom Gabon Oil Company Maroc Maroc 17 7.50% Maurel & Prom Gabon Oil Company Maroc Nord Maroc Nord 17 7.50% Maurel & Prom Gabon Oil Company Mbigou Mbigou 5 7.50% Maurel & Prom Gabon Oil Company M'Oba M'Oba 57 24.31% Perenco Gabon Oil Company Niembi Niembi 4 7.50% Maurel & Prom Gabon Oil Company Niungo Niungo 96 40.00% Perenco Gabon Oil Company Oba Oba 44 10.00% Perenco Gabon Oil Company Omko Omko 16 7.50% Maurel & Prom Gabon Oil Company Onal Onal 46 7.50% Maurel & Prom Gabon Oil Company Simba Simba 315 57.50% Perenco Tchatamba Marin Tchatamba Marin 30 25.00% Perenco ONE-Dyas BV Tchatamba South Tchatamba South 40 25.00% Perenco ONE-Dyas BV Tchatamba West Tchatamba West 25 25.00% Perenco ONE-Dyas BV Turnix Turnix 18 27.50% Perenco Gabon Oil Company Note 31. Licence interests continued Kenya Licence Fields Area sq km Tullow interest Operator Other partners Kenya Block 10BA 11,569 50.00% Tullow Centric Energy, TotalEnergies Block 10BB Amosing, Ngamia 6,172 50.00% Tullow Africa Oil, TotalEnergies Block 12B 6,200 100.00% Tullow Block 13T Ekales, Twiga 4,719 50.00% Tullow Africa Oil, TotalEnergies Exploration Licence/Unit area Fields Area sq km Tullow interest Operator Other partners Argentina Block MLO-114 5,942 40.00% Tullow Pluspetrol, Wintershall Dea Block MLO-119 4,546 40.00% Tullow Pluspetrol, Wintershall Dea Block MLO-122 4,420 100.00% Tullow C\u00f4te d\u2019Ivoire CI-524 551 90.00% Tullow Petroci CI-803 1,345 90.00% Tullow Petroci Guyana Kanuku 4,154 37.50% Repsol TOQAP Orinduik 1,776 60.00% Tullow TOQAP, Eco Atlantic O&G",
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