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The address of the registered office 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 first time for their annual reporting period commencing 1 January 2023: \u2022 IFRS 17 Insurance Contracts \u2022 Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2 \u2022 Definition of Accounting Estimates \u2013 Amendments to IAS 8 \u2022 Deferred Tax related to Assets and Liabilities arising from a Single Transaction \u2013 Amendments to IAS 12 The amendments listed above did not have any impact on the amounts recognised in prior periods and are not expected to significantly affect the current or future periods. \u2022 International Tax Reform \u2013 Pillar Two Model Rules \u2013 Amendments to IAS 12 On 23 May 2023 an amendment to IAS 12 was issued which introduced a temporary mandatory exception in IAS 12 from recognising and disclosing deferred tax assets and liabilities related to the top-up tax, which is effective immediately and require new disclosures about the Pillar Two exposures. The amendments clarify that IAS 12 applies to income taxes arising from tax law enacted or substantively enacted to implement the Pillar Two Model Rules published by the Organization for Economic Cooperation and Development (OECD), including tax law that implements qualified domestic minimum top-up taxes. The mandatory exception applies retrospectively. However, because no new legislation to implement the top-up tax was enacted or substantively enacted on 31 December 2022 in any jurisdiction in which the Group operates and no related deferred tax was recognised at that date, the retrospective application has no impact on the Group\u2019s consolidated Financial Statements. 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 2023 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\u2019s accounting policies are consistent with the prior year. (d) Basis of preparation The Financial Statements have 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 financial reporting framework that has been applied in the preparation of the Parent Company Financial 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 financial instruments and contingent considerations which have been measured 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 material 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 2025. 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: \u2022 Base Case: $78/bbl for 2024, $75/bbl for 2024; and \u2022 Low Case: $70/bbl for 2024, $70/bbl for 2025. The Low Case includes, amongst other downside assumptions, a 10% production decrease and 10% increased operating costs compared to the Base Case. Management has also considered additional outflows in respect of all ongoing litigations/arbitrations within the Low Case, with an additional $48 million outflow being included for the cases expected to progress in the period under assessment. The low case does not include the outflow for the full exposure on Ghana BPRT arbitration of $320 million (refer to Note 1(af) Ghana tax assessments for details). The remaining arbitration cases are not expected to conclude within the going concern period and no outflows have been included in that respect. At 31 December 2023, the Group had $1.0 billion liquidity headroom consisting of c.$0.5 billion free cash and $0.5 billion available under the revolving credit facility. The Group or its affiliates may, at any time and from time to Assessment period and assumptions continued 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. The Group has repaid $0.3 billion and $0.2 billion of the 2025 and 2026 Notes, respectively, during the year. The repayment of the 2025 Notes was partially funded by a drawdown of $130 million of the Glencore facility. The Group\u2019s forecasts show that the Group and Parent Company will be able to operate within its current debt facilities and have sufficient financial headroom for the going concern assessment period under its Base Case and Low Case at the end of the going concern period, including a full drawdown of the Glencore debt facility to support the payment of the 2025 Notes. The Directors have also performed a reverse stress test to establish the average oil price throughout the going concern period required to reduce headroom to zero, that price was determined to be $45/bbl. Based on the analysis above, the Directors have a reasonable expectation that the Group and Parent Company 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 Annual Report and Accounts. (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 profit 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 classified 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:
\u2022 Fair values of the assets transferred.
\u2022 Liabilities incurred to the former owners of the
acquired business.
\u2022 Equity interests issued by the Group.
\u2022 Fair value of any asset or liability resulting from a
contingent consideration arrangement.
\u2022 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 significantly
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 significantly contributes to the ability
to continue producing outputs and is considered unique
or scarce or cannot be replaced without significant cost,
effort, or delay in the ability to continue producing outputs.
Identifiable 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 identifiable
assets acquired is recorded as goodwill. If those amounts
are less than the fair value of the net identifiable assets of
the business acquired, the difference is recognised directly
in profit 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 reflects 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.
i) Revenue from crude oil sales
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 over/underlift
(note (h)) 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 profit 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 expense with a corresponding amount
recognised in Revenue.
The Group\u2019s sales of crude oil are priced based on the
consideration specified 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\u2013operated 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 profit oil.
ii) Revenue from gas sales
Revenue associated with the sale of natural gas in Ghana is
measured in line with the consideration agreed per MMBtu
in the existing sales contracts with offtakers. The transfer of
control occurs when title passes at the point the customer
takes physical delivery. The Group principally satisfies its
performance obligations at a point in time and the amounts
of revenue recognised relating to performance obligations
satisfied over time are not significant.
(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 profit 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 Financial
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 classified 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 profit or loss on disposal of the net investment. (k) Assets classified as held for sale Non-current assets or disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell. A loss for any initial or subsequent write-down of the asset or disposal group to a revised fair value less costs to sell is recognised at each reporting date. Non-current assets and disposal groups are classified as held for sale if their carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset (or disposal group) is available for immediate sale in its present condition. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification. Assets and corresponding liabilities classified as held for sale are presented separately as current items in the statement of financial position. (l) 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, field 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 reclassified 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 field 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 profit or loss.
(m) Commercial reserves
Commercial reserves are proven and probable oil
and gas reserves, which are defined as the estimated
quantities of crude oil, natural gas and natural gas liquids
which geological, geophysical and engineering data
demonstrate with a specified 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.
(n) Depletion and amortisation
All expenditure carried within each field 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 field-by-field basis or by a group of
fields 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 field development costs required to recover the
commercial reserves remaining. Changes in the estimates
of commercial reserves or future field development costs
are dealt with prospectively.
(o) Impairment of property, plant
and equipment
The Group assesses at each reporting date whether there
is an indication that an asset or Cash Generating Unit (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 flow model.
In order to discount the future cash flows the Group
calculates asset or CGU-specific 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 fields, such as common infrastructure, the fields
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.
(p) 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 finance cost.
(q) 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.
(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) 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 finance costs, which include interest on
borrowings calculated using the effective interest method
as described in paragraph (aa), obligations under finance
leases, the unwinding effect of discounting provisions
and exchange differences, are recognised in the income
statement in the period in which they are incurred.
(t) 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 profits 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.
(u) Pensions
Contributions to the Group\u2019s defined contribution pension
schemes are charged to operating profit on an accrual basis.
(v) Derivative financial instruments
The Group uses derivative financial 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 profit or loss
immediately unless the derivative is designated and
effective as a hedging instrument, in which event the
timing of the recognition in profit or loss depends on the
nature of the hedge relationship.
For the purpose of hedge accounting, hedges are classified as:
\u2022 Fair value hedges when hedging the exposure to
changes in the fair value of a recognised asset or liability
or an unrecognised firm commitment.
\u2022 Cash flow hedges when hedging the exposure to
variability in cash flows that is either attributable to a
particular risk, or associated with a recognised asset
or liability or a highly probable forecast transaction
or the foreign currency risk in an unrecognised firm
commitment.
\u2022 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.
The documentation includes identification 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 qualifies for hedge accounting if it
meets all of the following effectiveness requirements:
\u2022 There is \u2018an economic relationship\u2019 between the hedged
item and the hedging instrument.
\u2022 The effect of credit risk does not \u2018dominate the value
changes\u2019 that result from that economic relationship.
\u2022 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
reclassified to profit or loss when the hedged item affects
profit or loss. If the hedged item is time period-related, then
the amount accumulated in the time value hedge reserve
is reclassified to profit or loss on a rational basis. Those
reclassified amounts are recognised in profit 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 reclassified to profit or loss.
Cash flow hedges
The effective portion of the gain or loss on the hedging
instrument is recognised in OCI in the cash flow hedge
reserve, while any ineffective portion is recognised
immediately in the statement of profit or loss. The
cash flow 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 reclassified to profit
or loss in the periods when the hedged item affects profit
or loss, in the same line as the recognised hedged item.
Cash flow 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 flow hedge accounting
is discontinued, amounts previously recognised within other
comprehensive income remain in equity until the forecast
transaction occurs and are reclassified to profit or loss or
transferred to the initial carrying amount of a non-financial
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
reclassified to profit or loss.
(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 identified asset for a period of time in exchange
for consideration. To determine whether the contract
conveys the right to control the use of an identified asset,
the Group assesses whether the contract involves the use
of an identified asset, the Group has the right to obtain
substantially all of the economic benefits from the use of
the asset throughout the period of use, and the Group has
the right to direct the use of the asset.
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 fixed 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 profit 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 flexibility 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 defined 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 modifications 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.
(y) Financial assets
At initial recognition, the Group measures a financial
asset at its fair value plus, in the case of a financial asset
not at fair value through profit or loss (FVPL), transaction
costs that are directly attributable to the acquisition of the
financial asset. Transaction costs of financial assets carried
at FVPL are expensed in profit or loss.
The subsequent measurement of financial assets depends
on their classification, as set out overleaf.
i) Financial assets measured at amortised cost
Assets are subsequently classified and measured at
amortised cost when the business model of the Company
is to collect contractual cash flows and the contractual
terms give rise to cash flows 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 significant. Gains and losses
are recognised in profit or loss when the assets are
derecognised, modified or impaired. This category of
financial assets includes trade and other receivables.
Financial assets measured at amortised cost include trade
receivables, loans and other receivables that have fixed 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.
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 financial asset to that asset\u2019s net carrying amount.
ii) Financial assets measured at fair value through other comprehensive income Assets are subsequently classified and measured at fair value through other comprehensive income when the business model of the Company is to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and interest. iii) Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit 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 2023, the Group does not have any financial assets classified at fair value through profit or loss or other comprehensive income. Regular way purchases and sales of financial 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 flows from the financial 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 simplified 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 profiles of sales over the historical period and the corresponding historical credit losses experienced during 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 2023 would be immaterial; therefore, in line with IFRS 9, no impairment was recognised (2022: $nil). In order to minimise the risk of default, credit risk is managed on a Group basis (note 17). (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 insignificant risk of changes in value. The effective interest method is a method of calculating the amortised cost of a financial 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 financial asset, or, where appropriate, a shorter period. Income is recognised on an effective interest basis for debt instruments other than those financial assets classified as at FVTPL.(ab) Financial liabilities The measurement of financial liabilities is determined by the initial classification. i) Financial liabilities at fair value through profit or loss: Those balances that meet the definition of being held for trading are measured at fair value through profit 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 financial liabilities not meeting the criteria of being classified at fair value through profit or loss are classified as financial 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 financial liability. Subsequent to initial recognition, financial liabilities are measured at amortised cost using the effective interest method. Trade payables and borrowings fall under this category of financial instruments. As at 31 December 2023 all financial liabilities are measured at amortised cost. The Group derecognises a financial liability when it is extinguished, i.e. when the obligation specified in the contract is discharged or cancelled or expires. A substantial modification of the terms of an existing financial liability or a part of it is accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability. The difference between the carrying amount of the financial liability extinguished and any consideration paid is recognised in the Income Statement as other income if the transaction results in a gain, or finance costs if the result is a loss. iii) Offsetting of financial instruments: Financial assets and financial liabilities are offset and the net amount is reported in the consolidated statement of financial 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 classified 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) 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 outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. (ae) 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 (af), that the Directors have made in the process of applying the Group\u2019s accounting policies and that have the most significant 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 specific 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 8. The most material area where judgement was applied during 2023 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. Triggers for an impairment assessment were identified following the withdrawal of the JV partners and an increase in Group\u2019s long-term oil price assumption, resulting in an increase in
Carrying value of intangible exploration and
evaluation assets (note 9)
the underlying value of the project. Due to the stage of this
project being pre-final 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 profiles
and certain fiscal terms. Furthermore, the Group has
identified 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 financing for the
project and government deliverables in form of provision
of required infrastructure and fiscal terms. 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 flows
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 an impairment charge of $17.9
million was booked as at 31 December 2023. 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 additional impairment of $242.2 million.
(af) 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 significant risk of causing a material
adjustment to the carrying amounts of assets and liabilities
within the next financial year, are discussed below.
Carrying value of property, plant and equipment
(note 9)
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 flows 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 profiles.
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 191).
The estimation applied by management to the exploration
risk premium adjustment to its impairment discount
rates, estimated future commodity prices and forecast
cash flows on the TEN asset would have the most
material impact on the 2023 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 9.
Lease accounting (note 18)
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
at the lease commencement date if the interest rate
implicit in the lease is not readily determinable. For the
material remeasurements during the year, predominantly
on the TEN FPSO lease discussed in note 18 the Group has
assessed the incremental borrowing rate to be 16.88%.
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 flexibility
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.
In respect of the TEN FPSO lease, the lease term was
updated to reflect the management\u2019s best estimate view
that the FPSO will continue to be leased until the cessation
of production in 2032 and assumes an exercise of the
extension option following a decision not to exercise the
purchase option.
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 financial
impact based on external tax and legal advice and prior
experience of such claims.
Provisions of $85.0 million (2022: $106.4 million) are included
in income tax payable ($78.3 million (2022: $70.6 million)),
deferred tax liability ($nil (2022: $nil)), and provisions ($6.7
million (2022: $35.8 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.
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 significantly from management\u2019s estimate. If the
Group was unsuccessful in defending itself from all of these
claims, the result would be additional liabilities of $1,030.3
million (2022: $1,024.0 million) which includes $6.9 million
of interest and penalties (2022: $32.4 million).
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 2023, giving rise to an overall decrease
in provision of $21.4 million and increase in contingent
liability of $6.2 million.
Ghana tax assessments
In October 2021, Tullow Ghana Limited (TGL) filed a
Request for Arbitration with the International Chamber
of Commerce (ICC) disputing the $320.3 million branch
profits remittance tax (BPRT) assessment issued as part of
the direct tax audit for the financial 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 arbitration hearing took place in October 2023 and a
decision is expected in the current financial year. TGL is
not required to pay any amounts of BPRT until the dispute
is formally resolved.
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
financial 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 filed 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. The arbitration hearing
is scheduled to commence on 30 June 2025.
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 financial 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
filed 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 arbitration hearing is scheduled to
commence on 17 November 2025. The Group continues
to engage with the Government of Ghana with the aim of
resolving the BPRT, loan interest and insurance disputes on
a mutually acceptable basis.
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow
$118.6 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 3,094.3 million (c.$29.3 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 first submissions have been made in
October 2022 with counter submissions received on 17
January 2023. The second submission was made in June
2023 with the first Tribunal hearing scheduled for 20-24
May 2024. A decision is expected in H1 2025.
Other items
Other items totalling $294.0 million (2022: $280.0 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 flows
While it is not possible to estimate the timing and amount
of tax cash flows in relation to possible outcomes with
certainty, as they are subject to outcome of court/
arbitration proceedings and any potential appeals,
management anticipates that there will not be material
cash taxes paid in excess of the amounts provided for
uncertain tax treatments.
", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-327": { "value": "
(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 office 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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-2": { "value": "Tullow Oil plc", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-3": { "value": "United Kingdom", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-324": { "value": "United Kingdom", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-4": { "value": "Tullow Oil plc, Building 9, Chiswick Park, 566 Chiswick High Road, London W4 5XT", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-5": { "value": "The primary activity of the Group is the discovery and production of oil and gas. ", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-328": { "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 first time for their annual reporting
period commencing 1 January 2023:
\u2022 IFRS 17 Insurance Contracts
\u2022 Disclosure of Accounting Policies \u2013 Amendments to IAS
1 and IFRS Practice Statement 2
\u2022 Definition of Accounting Estimates \u2013 Amendments to IAS 8
\u2022 Deferred Tax related to Assets and Liabilities arising from
a Single Transaction \u2013 Amendments to IAS 12
The amendments listed above did not have any impact
on the amounts recognised in prior periods and are not
expected to significantly affect the current or future periods.
\u2022 International Tax Reform \u2013 Pillar Two
Model Rules \u2013 Amendments to IAS 12
On 23 May 2023 an amendment to IAS 12 was issued which
introduced a temporary mandatory exception in IAS 12 from
recognising and disclosing deferred tax assets and liabilities
related to the top-up tax, which is effective immediately and
require new disclosures about the Pillar Two exposures.
The amendments clarify that IAS 12 applies to income
taxes arising from tax law enacted or substantively
enacted to implement the Pillar Two Model Rules
published by the Organization for Economic Cooperation
and Development (OECD), including tax law that
implements qualified domestic minimum top-up taxes.
The mandatory exception applies retrospectively.
However, because no new legislation to implement the
top-up tax was enacted or substantively enacted on 31
December 2022 in any jurisdiction in which the Group
operates and no related deferred tax was recognised at
that date, the retrospective application has no impact on
the Group\u2019s consolidated Financial Statements.
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 2023
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\u2019s accounting policies are consistent with the prior year", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-385": { "value": "New International Financial Reporting Standards adopted The Group has applied the following standards and amendments for the first time for their annual reporting period commencing 1 January 2023: \u2022 IFRS 17 Insurance Contracts \u2022 Disclosure of Accounting Policies \u2013 Amendments to IAS 1 and IFRS Practice Statement 2 \u2022 Definition of Accounting Estimates \u2013 Amendments to IAS 8 \u2022 Deferred Tax related to Assets and Liabilities arising from a Single Transaction \u2013 Amendments to IAS 12 The amendments listed above did not have any impact on the amounts recognised in prior periods and are not expected to significantly affect the current or future periods. \u2022 International Tax Reform \u2013 Pillar Two Model Rules \u2013 Amendments to IAS 12 On 23 May 2023 an amendment to IAS 12 was issued which introduced a temporary mandatory exception in IAS 12 from recognising and disclosing deferred tax assets and liabilities related to the top-up tax, which is effective immediately and require new disclosures about the Pillar Two exposures. The amendments clarify that IAS 12 applies to income taxes arising from tax law enacted or substantively enacted to implement the Pillar Two Model Rules published by the Organization for Economic Cooperation and Development (OECD), including tax law that implements qualified domestic minimum top-up taxes. The mandatory exception applies retrospectively. However, because no new legislation to implement the top-up tax was enacted or substantively enacted on 31 December 2022 in any jurisdiction in which the Group operates and no related deferred tax was recognised at that date, the retrospective application has no impact on the Group\u2019s consolidated Financial Statements. ", "dimensions": { "concept": "ifrs-full:DescriptionOfInitialApplicationOfStandardsOrInterpretations", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-386": { "value": "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 2023 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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfExpectedImpactOfInitialApplicationOfNewStandardsOrInterpretations", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-329": { "value": "
(d) Basis of preparation
The Financial Statements have 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
financial reporting framework that has been applied in the
preparation of the Parent Company Financial 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 financial
instruments and contingent considerations which
have been measured 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 material 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 2025. 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:
\u2022 Base Case: $78/bbl for 2024, $75/bbl for 2024; and
\u2022 Low Case: $70/bbl for 2024, $70/bbl for 2025.
The Low Case includes, amongst other downside
assumptions, a 10% production decrease and 10%
increased operating costs compared to the Base Case.
Management has also considered additional outflows in
respect of all ongoing litigations/arbitrations within the
Low Case, with an additional $48 million outflow being
included for the cases expected to progress in the period
under assessment. The low case does not include the
outflow for the full exposure on Ghana BPRT arbitration of
$320 million (refer to Note 1(af) Ghana tax assessments for
details). The remaining arbitration cases are not expected
to conclude within the going concern period and no
outflows have been included in that respect.
At 31 December 2023, the Group had $1.0 billion liquidity
headroom consisting of c.$0.5 billion free cash and $0.5
billion available under the revolving credit facility.
The Group 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. The Group has repaid $0.3 billion and $0.2 billion of the 2025 and 2026 Notes, respectively, during the year. The repayment of the 2025 Notes was partially funded by a drawdown of $130 million of the Glencore facility. The Group\u2019s forecasts show that the Group and Parent Company will be able to operate within its current debt facilities and have sufficient financial headroom for the going concern assessment period under its Base Case and Low Case at the end of the going concern period, including a full drawdown of the Glencore debt facility to support the payment of the 2025 Notes. The Directors have also performed a reverse stress test to establish the average oil price throughout the going concern period required to reduce headroom to zero, that price was determined to be $45/bbl. Based on the analysis above, the Directors have a reasonable expectation that the Group and Parent Company 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 Annual Report and Accounts. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-387": { "value": "The Financial Statements have 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.", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "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 2025. 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: \u2022 Base Case: $78/bbl for 2024, $75/bbl for 2024; and \u2022 Low Case: $70/bbl for 2024, $70/bbl for 2025. The Low Case includes, amongst other downside assumptions, a 10% production decrease and 10% increased operating costs compared to the Base Case. Management has also considered additional outflows in respect of all ongoing litigations/arbitrations within the Low Case, with an additional $48 million outflow being included for the cases expected to progress in the period under assessment. The low case does not include the outflow for the full exposure on Ghana BPRT arbitration of $320 million (refer to Note 1(af) Ghana tax assessments for details). The remaining arbitration cases are not expected to conclude within the going concern period and no outflows have been included in that respect. At 31 December 2023, the Group had $1.0 billion liquidity headroom consisting of c.$0.5 billion free cash and $0.5 billion available under the revolving credit facility. The Group 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. The Group has repaid $0.3 billion and $0.2 billion of the 2025 and 2026 Notes, respectively, during the year. The repayment of the 2025 Notes was partially funded by a drawdown of $130 million of the Glencore facility. The Group\u2019s forecasts show that the Group and Parent Company will be able to operate within its current debt facilities and have sufficient financial headroom for the going concern assessment period under its Base Case and Low Case at the end of the going concern period, including a full drawdown of the Glencore debt facility to support the payment of the 2025 Notes. The Directors have also performed a reverse stress test to establish the average oil price throughout the going concern period required to reduce headroom to zero, that price was determined to be $45/bbl. Based on the analysis above, the Directors have a reasonable expectation that the Group and Parent Company 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 Annual Report and Accounts. Liquidity risk The Group manages its liquidity risk using both short-term and long-term cash flow projections, supplemented by debt financing 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 $1.0 billion (2022: $1.1 billion) of total facility headroom and free cash as at 31 December 2023. The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative financial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Group can be required to pay.
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $m
31 December 2023
Non-interest bearing
n/a
49.5
\u2013
38.1
62.2
\u2013
149.8
Lease liabilities
16.4%
45.3
55.8
203.7
734.2
337.5
1,376.5
Fixed interest rate instruments
9.9%
Principal repayments
\u2013
\u2013
100.0
1,878.0
\u2013
1,978.0
Interest charge
\u2013
17.0
164.0
220.0
\u2013
401.0
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
\u2013
5.0
15.0
69.0
\u2013
89.0
Total
94.8
77.8
520.8
3,093.4
337.5
4,124.3
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $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
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-388": { "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 2025. 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: \u2022 Base Case: $78/bbl for 2024, $75/bbl for 2024; and \u2022 Low Case: $70/bbl for 2024, $70/bbl for 2025. The Low Case includes, amongst other downside assumptions, a 10% production decrease and 10% increased operating costs compared to the Base Case. Management has also considered additional outflows in respect of all ongoing litigations/arbitrations within the Low Case, with an additional $48 million outflow being included for the cases expected to progress in the period under assessment. The low case does not include the outflow for the full exposure on Ghana BPRT arbitration of $320 million (refer to Note 1(af) Ghana tax assessments for details). The remaining arbitration cases are not expected to conclude within the going concern period and no outflows have been included in that respect. At 31 December 2023, the Group had $1.0 billion liquidity headroom consisting of c.$0.5 billion free cash and $0.5 billion available under the revolving credit facility. The Group 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. The Group has
repaid $0.3 billion and $0.2 billion of the 2025 and 2026
Notes, respectively, during the year. The repayment of the
2025 Notes was partially funded by a drawdown of $130
million of the Glencore facility.
The Group\u2019s forecasts show that the Group and Parent
Company will be able to operate within its current debt
facilities and have sufficient financial headroom for the
going concern assessment period under its Base Case and
Low Case at the end of the going concern period, including
a full drawdown of the Glencore debt facility to support
the payment of the 2025 Notes. The Directors have also
performed a reverse stress test to establish the average
oil price throughout the going concern period required to
reduce headroom to zero, that price was determined to be
$45/bbl. Based on the analysis above, the Directors have a
reasonable expectation that the Group and Parent Company
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 Annual Report
and Accounts.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGoingConcernExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-389": { "value": "
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 profit 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.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSubsidiariesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-331": { "value": "Joint arrangements The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-391": { "value": "Joint arrangements The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified 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:DescriptionOfAccountingPolicyForInvestmentsInJointVentures", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-428": { "value": "Joint arrangements The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified 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:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-427": { "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: \u2022 Fair values of the assets transferred. \u2022 Liabilities incurred to the former owners of the acquired business. \u2022 Equity interests issued by the Group. \u2022 Fair value of any asset or liability resulting from a contingent consideration arrangement. \u2022 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 significantly 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 significantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay in the ability to continue producing outputs. Identifiable 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 identifiable assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net identifiable assets of the business acquired, the difference is recognised directly in profit or loss as a bargain purchase. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-390": { "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: \u2022 Fair values of the assets transferred. \u2022 Liabilities incurred to the former owners of the acquired business. \u2022 Equity interests issued by the Group. \u2022 Fair value of any asset or liability resulting from a contingent consideration arrangement. \u2022 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 significantly 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 significantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay in the ability to continue producing outputs. Identifiable 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 identifiable assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net identifiable assets of the business acquired, the difference is recognised directly in profit or loss as a bargain purchase. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-330": { "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: \u2022 Fair values of the assets transferred. \u2022 Liabilities incurred to the former owners of the acquired business. \u2022 Equity interests issued by the Group. \u2022 Fair value of any asset or liability resulting from a contingent consideration arrangement. \u2022 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 significantly 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 significantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay in the ability to continue producing outputs. Identifiable 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 identifiable assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net identifiable assets of the business acquired, the difference is recognised directly in profit or loss as a bargain purchase. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-335": { "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 reflects 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. i) Revenue from crude oil sales 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 over/underlift (note (h)) 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 profit 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 expense with a corresponding amount recognised in Revenue. The Group\u2019s sales of crude oil are priced based on the consideration specified 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\u2013operated 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 profit oil. ii) Revenue from gas sales Revenue associated with the sale of natural gas in Ghana is measured in line with the consideration agreed per MMBtu in the existing sales contracts with offtakers. The transfer of control occurs when title passes at the point the customer takes physical delivery. The Group principally satisfies its performance obligations at a point in time and the amounts of revenue recognised relating to performance obligations satisfied over time are not significant. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-332": { "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 profit is recognised on an entitlements basis. ", "dimensions": { "concept": "tullowoilplc:DescriptionOfAccountingPolicyForOverUnderlift", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-333": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-392": { "value": "(j) Foreign currencies The US dollar is the presentational currency of the Group. For the purpose of presenting consolidated Financial 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 classified 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 profit or loss on disposal of the net investment.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-334": { "value": "(j) Foreign currencies The US dollar is the presentational currency of the Group. For the purpose of presenting consolidated Financial 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 classified 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 profit or loss on
disposal of the net investment.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-340": { "value": "
(k) Assets classified as held for sale
Non-current assets or disposal groups classified as held
for sale are measured at the lower of carrying amount
and fair value less costs to sell. A loss for any initial or
subsequent write-down of the asset or disposal group to
a revised fair value less costs to sell is recognised at each
reporting date. Non-current assets and disposal groups
are classified as held for sale if their
carrying amount will be recovered through a sale
transaction rather than through continuing use. This
condition is regarded as met only when the sale is highly
probable and the asset (or disposal group) is available for
immediate sale in its present condition. Management must
be committed to the sale, which should be expected to
qualify for recognition as a completed sale within one year
from the date of classification. Assets and corresponding
liabilities classified as held for sale are
presented separately as current items in the statement of
financial position.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleAndDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-394": { "value": "(k) Assets classified as held for sale Non-current assets or disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell. A loss for any initial or subsequent write-down of the asset or disposal group to a revised fair value less costs to sell is recognised at each reporting date. Non-current assets and disposal groups are classified as held for sale if their carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset (or disposal group) is available for immediate sale in its present condition. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification. Assets and corresponding liabilities classified as held for sale are presented separately as current items in the statement of financial position. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-393": { "value": "
(l) 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, field 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 reclassified 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 field 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 profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-337": { "value": "(l) 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, field 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 reclassified 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 field 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 profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsOtherThanGoodwillExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-429": { "value": "(l) 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, field 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 reclassified 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 field 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 profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-336": { "value": "(m) Commercial reserves Commercial reserves are proven and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-430": { "value": "(n) Depletion and amortisation All expenditure carried within each field 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 field-by-field basis or by a group of fields 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 field development costs required to recover the commercial reserves remaining. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForExpensesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-395": { "value": "(n) Depletion and amortisation All expenditure carried within each field 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 field-by-field basis or by a group of fields 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 field development costs required to recover the commercial reserves remaining. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-338": { "value": "(n) Depletion and amortisation All expenditure carried within each field 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 field-by-field basis or by a group of fields 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 field development costs required to recover the commercial reserves remaining. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively. ", "dimensions": { "concept": "tullowoilplc:DescriptionOfAccountingPolicyForDepletionAndAmortisation", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-339": { "value": "(o) Impairment of property, plant and equipment The Group assesses at each reporting date whether there is an indication that an asset or Cash Generating Unit (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 flow model. In order to discount the future cash flows the Group calculates asset or CGU-specific 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 fields, such as common infrastructure, the fields 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-341": { "value": "(p) 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 finance cost. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-342": { "value": "(q) 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-345": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-399": { "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": "ifrs-full:DescriptionOfAccountingPolicyForIssuedCapitalExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-344": { "value": "(s) 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 finance costs, which include interest on borrowings calculated using the effective interest method as described in paragraph (aa), obligations under finance 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-398": { "value": "(s) 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 finance costs, which include interest on borrowings calculated using the effective interest method as described in paragraph (aa), obligations under finance 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:DescriptionOfAccountingPolicyForBorrowingsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-347": { "value": "(t) 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 profits 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-397": { "value": "(t) 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 profits 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-343": { "value": "(u) Pensions Contributions to the Group\u2019s defined contribution pension schemes are charged to operating profit on an accrual basis. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-346": { "value": "(v) Derivative financial instruments The Group uses derivative financial 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 profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship. For the purpose of hedge accounting, hedges are classified as: \u2022 Fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability or an unrecognised firm commitment. \u2022 Cash flow hedges when hedging the exposure to variability in cash flows that is either attributable to a particular risk, or associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an unrecognised firm commitment. \u2022 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. The documentation includes identification 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 qualifies for hedge accounting if it meets all of the following effectiveness requirements: \u2022 There is \u2018an economic relationship\u2019 between the hedged item and the hedging instrument. \u2022 The effect of credit risk does not \u2018dominate the value changes\u2019 that result from that economic relationship. \u2022 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 reclassified to profit or loss when the hedged item affects profit or loss. If the hedged item is time period-related, then the amount accumulated in the time value hedge reserve is reclassified to profit or loss on a rational basis. Those reclassified amounts are recognised in profit 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 reclassified to profit or loss. Cash flow hedges The effective portion of the gain or loss on the hedging instrument is recognised in OCI in the cash flow hedge reserve, while any ineffective portion is recognised immediately in the statement of profit or loss. The cash flow 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 reclassified to profit or loss in the periods when the hedged item affects profit or loss, in the same line as the recognised hedged item. Cash flow 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 flow hedge accounting is discontinued, amounts previously recognised within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred to the initial carrying amount of a non-financial 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 reclassified to profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-396": { "value": "(v) Derivative financial instruments The Group uses derivative financial 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 profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship. For the purpose of hedge accounting, hedges are classified as: \u2022 Fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability or an unrecognised firm commitment. \u2022 Cash flow hedges when hedging the exposure to variability in cash flows that is either attributable to a particular risk, or associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an unrecognised firm commitment. \u2022 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. The documentation includes identification 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 qualifies for hedge accounting if it meets all of the following effectiveness requirements: \u2022 There is \u2018an economic relationship\u2019 between the hedged item and the hedging instrument. \u2022 The effect of credit risk does not \u2018dominate the value changes\u2019 that result from that economic relationship. \u2022 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 reclassified to profit or loss when the hedged item affects profit or loss. If the hedged item is time period-related, then the amount accumulated in the time value hedge reserve is reclassified to profit or loss on a rational basis. Those reclassified amounts are recognised in profit 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 reclassified to profit or loss. Cash flow hedges The effective portion of the gain or loss on the hedging instrument is recognised in OCI in the cash flow hedge reserve, while any ineffective portion is recognised immediately in the statement of profit or loss. The cash flow 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 reclassified to profit or loss in the periods when the hedged item affects profit or loss, in the same line as the recognised hedged item. Cash flow 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 flow hedge accounting is discontinued, amounts previously recognised within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred to the initial carrying amount of a non-financial 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 reclassified to profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-445": { "value": "(v) Derivative financial instruments The Group uses derivative financial 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 profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship. For the purpose of hedge accounting, hedges are classified as: \u2022 Fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability or an unrecognised firm commitment. \u2022 Cash flow hedges when hedging the exposure to variability in cash flows that is either attributable to a particular risk, or associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an unrecognised firm commitment. \u2022 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. The documentation includes identification 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 qualifies for hedge accounting if it meets all of the following effectiveness requirements: \u2022 There is \u2018an economic relationship\u2019 between the hedged item and the hedging instrument. \u2022 The effect of credit risk does not \u2018dominate the value changes\u2019 that result from that economic relationship. \u2022 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 reclassified to profit or loss when the hedged item affects profit or loss. If the hedged item is time period-related, then the amount accumulated in the time value hedge reserve is reclassified to profit or loss on a rational basis. Those reclassified amounts are recognised in profit 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 reclassified to profit or loss. Cash flow hedges The effective portion of the gain or loss on the hedging instrument is recognised in OCI in the cash flow hedge reserve, while any ineffective portion is recognised immediately in the statement of profit or loss. The cash flow 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 reclassified to profit or loss in the periods when the hedged item affects profit or loss, in the same line as the recognised hedged item. Cash flow 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 flow hedge accounting is discontinued, amounts previously recognised within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred to the initial carrying amount of a non-financial 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 reclassified to profit or loss. (y) Financial assets At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss (FVPL), transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVPL are expensed in profit or loss. The subsequent measurement of financial assets depends on their classification, as set out overleaf. i) Financial assets measured at amortised cost Assets are subsequently classified and measured at amortised cost when the business model of the Company is to collect contractual cash flows and the contractual terms give rise to cash flows 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 significant. Gains and losses are recognised in profit or loss when the assets are derecognised, modified or impaired. This category of financial assets includes trade and other receivables. Financial assets measured at amortised cost include trade receivables, loans and other receivables that have fixed 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. 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 financial asset to that asset\u2019s net carrying amount. ii) Financial assets measured at fair value through other comprehensive income Assets are subsequently classified and measured at fair value through other comprehensive income when the business model of the Company is to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and interest. iii) Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit 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 2023, the Group does not have any financial assets classified at fair value through profit or loss or other comprehensive income. Regular way purchases and sales of financial 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 flows from the financial 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 simplified 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 profiles of sales over the historical period and the corresponding historical credit losses experienced during 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 2023 would be immaterial; therefore, in line with IFRS 9, no impairment was recognised (2022: $nil). In order to minimise the risk of default, credit risk is managed on a Group basis (note 17).
(ab) Financial liabilities
The measurement of financial liabilities is determined by
the initial classification.
i) Financial liabilities at fair value through profit
or loss:
Those balances that meet the definition of being held for
trading are measured at fair value through profit 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 financial liabilities not meeting the criteria of being
classified at fair value through profit or loss are classified
as financial 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
financial liability. Subsequent to initial recognition, financial
liabilities are measured at amortised cost using the effective
interest method. Trade payables and borrowings fall under
this category of financial instruments.
As at 31 December 2023 all financial liabilities are
measured at amortised cost.
The Group derecognises a financial liability when it
is extinguished, i.e. when the obligation specified in
the contract is discharged or cancelled or expires. A
substantial modification of the terms of an existing
financial liability or a part of it is accounted for as an
extinguishment of the original financial liability and the
recognition of a new financial liability.
The difference between the carrying amount of the
financial liability extinguished and any consideration paid
is recognised in the Income Statement as other income
if the transaction results in a gain, or finance costs if the
result is a loss.
iii) Offsetting of financial instruments:
Financial assets and financial liabilities are offset and the
net amount is reported in the consolidated statement of
financial 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:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-431": { "value": "(v) Derivative financial instruments The Group uses derivative financial 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 profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship. For the purpose of hedge accounting, hedges are classified as: \u2022 Fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability or an unrecognised firm commitment. \u2022 Cash flow hedges when hedging the exposure to variability in cash flows that is either attributable to a particular risk, or associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an unrecognised firm commitment. \u2022 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. The documentation includes identification 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 qualifies for hedge accounting if it meets all of the following effectiveness requirements: \u2022 There is \u2018an economic relationship\u2019 between the hedged item and the hedging instrument. \u2022 The effect of credit risk does not \u2018dominate the value changes\u2019 that result from that economic relationship. \u2022 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 reclassified to profit or loss when the hedged item affects profit or loss. If the hedged item is time period-related, then the amount accumulated in the time value hedge reserve is reclassified to profit or loss on a rational basis. Those reclassified amounts are recognised in profit 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 reclassified to profit or loss. Cash flow hedges The effective portion of the gain or loss on the hedging instrument is recognised in OCI in the cash flow hedge reserve, while any ineffective portion is recognised immediately in the statement of profit or loss. The cash flow 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 reclassified to profit or loss in the periods when the hedged item affects profit or loss, in the same line as the recognised hedged item. Cash flow 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 flow hedge accounting is discontinued, amounts previously recognised within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred to the initial carrying amount of a non-financial 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 reclassified to profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-348": { "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 identified asset for a period of time in exchange for consideration. To determine whether the contract conveys the right to control the use of an identified asset, the Group assesses whether the contract involves the use of an identified asset, the Group has the right to obtain substantially all of the economic benefits from the use of the asset throughout the period of use, and the Group has the right to direct the use of the asset. 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 fixed 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 profit 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 flexibility
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-349": { "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 defined 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 modifications 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-432": { "value": "(y) Financial assets At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss (FVPL), transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVPL are expensed in profit or loss. The subsequent measurement of financial assets depends on their classification, as set out overleaf. i) Financial assets measured at amortised cost Assets are subsequently classified and measured at amortised cost when the business model of the Company is to collect contractual cash flows and the contractual terms give rise to cash flows 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 significant. Gains and losses are recognised in profit or loss when the assets are derecognised, modified or impaired. This category of financial assets includes trade and other receivables. Financial assets measured at amortised cost include trade receivables, loans and other receivables that have fixed 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. 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 financial asset to that asset\u2019s net carrying amount. ii) Financial assets measured at fair value through other comprehensive income Assets are subsequently classified and measured at fair value through other comprehensive income when the business model of the Company is to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and interest. iii) Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit 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 2023, the Group does not have any financial assets classified at fair value through profit or loss or other comprehensive income. Regular way purchases and sales of financial 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 flows from the financial 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 simplified 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 profiles of sales over the historical period and the corresponding historical credit losses experienced during 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 2023 would be immaterial; therefore, in line with IFRS 9, no impairment was recognised (2022: $nil). In order to minimise the risk of default, credit risk is managed on a Group basis (note 17). (ab) Financial liabilities The measurement of financial liabilities is determined by the initial classification. i) Financial liabilities at fair value through profit or loss: Those balances that meet the definition of being held for trading are measured at fair value through profit 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 financial liabilities not meeting the criteria of being classified at fair value through profit or loss are classified as financial 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 financial liability. Subsequent to initial recognition, financial liabilities are measured at amortised cost using the effective interest method. Trade payables and borrowings fall under this category of financial instruments. As at 31 December 2023 all financial liabilities are measured at amortised cost. The Group derecognises a financial liability when it is extinguished, i.e. when the obligation specified in the contract is discharged or cancelled or expires. A substantial modification of the terms of an existing financial liability or a part of it is accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability. The difference between the carrying amount of the financial liability extinguished and any consideration paid is recognised in the Income Statement as other income if the transaction results in a gain, or finance costs if the result is a loss. iii) Offsetting of financial instruments: Financial assets and financial liabilities are offset and the net amount is reported in the consolidated statement of financial 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:DescriptionOfAccountingPolicyForFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-400": { "value": "(y) Financial assets At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss (FVPL), transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVPL are expensed in profit or loss. The subsequent measurement of financial assets depends on their classification, as set out overleaf. i) Financial assets measured at amortised cost Assets are subsequently classified and measured at amortised cost when the business model of the Company is to collect contractual cash flows and the contractual terms give rise to cash flows 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 significant. Gains and losses are recognised in profit or loss when the assets are derecognised, modified or impaired. This category of financial assets includes trade and other receivables. Financial assets measured at amortised cost include trade receivables, loans and other receivables that have fixed 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. 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 financial asset to that asset\u2019s net carrying amount. ii) Financial assets measured at fair value through other comprehensive income Assets are subsequently classified and measured at fair value through other comprehensive income when the business model of the Company is to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and interest. iii) Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit 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 2023, the Group does not have any financial assets classified at fair value through profit or loss or other comprehensive income. Regular way purchases and sales of financial 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 flows from the financial 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 simplified 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 profiles of sales over the historical period and the corresponding historical credit losses experienced during 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 2023 would be immaterial; therefore, in line with IFRS 9, no impairment was recognised (2022: $nil). In order to minimise the risk of default, credit risk is managed on a Group basis (note 17). (ab) Financial liabilities The measurement of financial liabilities is determined by the initial classification. i) Financial liabilities at fair value through profit or loss: Those balances that meet the definition of being held for trading are measured at fair value through profit 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 financial liabilities not meeting the criteria of being classified at fair value through profit or loss are classified as financial 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 financial liability. Subsequent to initial recognition, financial liabilities are measured at amortised cost using the effective interest method. Trade payables and borrowings fall under this category of financial instruments. As at 31 December 2023 all financial liabilities are measured at amortised cost. The Group derecognises a financial liability when it is extinguished, i.e. when the obligation specified in the contract is discharged or cancelled or expires. A substantial modification of the terms of an existing financial liability or a part of it is accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability. The difference between the carrying amount of the financial liability extinguished and any consideration paid is recognised in the Income Statement as other income if the transaction results in a gain, or finance costs if the result is a loss. iii) Offsetting of financial instruments: Financial assets and financial liabilities are offset and the net amount is reported in the consolidated statement of financial 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:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-350": { "value": "(y) Financial assets At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss (FVPL), transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVPL are expensed in profit or loss. The subsequent measurement of financial assets depends on their classification, as set out overleaf. i) Financial assets measured at amortised cost Assets are subsequently classified and measured at amortised cost when the business model of the Company is to collect contractual cash flows and the contractual terms give rise to cash flows 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 significant. Gains and losses are recognised in profit or loss when the assets are derecognised, modified or impaired. This category of financial assets includes trade and other receivables. Financial assets measured at amortised cost include trade receivables, loans and other receivables that have fixed 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. 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 financial asset to that asset\u2019s net carrying amount.
ii) Financial assets measured at fair value through
other comprehensive income
Assets are subsequently classified and measured at fair value
through other comprehensive income when the business
model of the Company is to collect contractual cash flows
and sell the financial assets, and the contractual cash flows
represent solely payments of principal and interest.
iii) Financial assets measured at fair value through
profit or loss
Financial assets are classified as measured at fair value
through profit 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 2023, the Group
does not have any financial assets classified at fair value
through profit or loss or other comprehensive income.
Regular way purchases and sales of financial 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
flows from the financial 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 simplified 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 profiles
of sales over the historical period and the corresponding
historical credit losses experienced during 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 2023 would be immaterial; therefore, in line
with IFRS 9, no impairment was recognised (2022: $nil).
In order to minimise the risk of default, credit risk is
managed on a Group basis (note 17).
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-351": { "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 insignificant risk of changes in value.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-352": { "value": "
(aa) Effective interest method
The effective interest method is a method of calculating
the amortised cost of a financial 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 financial asset, or, where
appropriate, a shorter period.
Income is recognised on an effective interest basis
for debt instruments other than those financial assets
classified as at FVTPL.
", "dimensions": { "concept": "tullowoilplc:DescriptionOfAccountingPolicyForEffectiveInterestMethod", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-401": { "value": "(aa) Effective interest method The effective interest method is a method of calculating the amortised cost of a financial 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 financial asset, or, where appropriate, a shorter period. Income is recognised on an effective interest basis for debt instruments other than those financial assets classified as at FVTPL.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInterestIncomeAndExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-353": { "value": "(ab) Financial liabilities The measurement of financial liabilities is determined by the initial classification. i) Financial liabilities at fair value through profit or loss: Those balances that meet the definition of being held for trading are measured at fair value through profit 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 financial liabilities not meeting the criteria of being classified at fair value through profit or loss are classified as financial 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 financial liability. Subsequent to initial recognition, financial liabilities are measured at amortised cost using the effective interest method. Trade payables and borrowings fall under this category of financial instruments. As at 31 December 2023 all financial liabilities are measured at amortised cost. The Group derecognises a financial liability when it is extinguished, i.e. when the obligation specified in the contract is discharged or cancelled or expires. A substantial modification of the terms of an existing financial liability or a part of it is accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability. The difference between the carrying amount of the financial liability extinguished and any consideration paid is recognised in the Income Statement as other income if the transaction results in a gain, or finance costs if the result is a loss. iii) Offsetting of financial instruments: Financial assets and financial liabilities are offset and the net amount is reported in the consolidated statement of financial 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-452": { "value": "iii) Offsetting of financial instruments: Financial assets and financial liabilities are offset and the net amount is reported in the consolidated statement of financial 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:DescriptionOfAccountingPolicyForOffsettingOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-354": { "value": "
(ac) Equity instruments
Equity instruments are classified 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-356": { "value": "
(ad) 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 outflow of resources embodying
economic benefits will be required to settle the obligation
and a reliable estimate can be made of the amount of
the obligation.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-355": { "value": "
(ae) 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 (af), that the Directors have made in the process of
applying the Group\u2019s accounting policies and that have the
most significant 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 specific
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 8.
The most material area where judgement was applied
during 2023 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. Triggers for
an impairment assessment were identified following the
withdrawal of the JV partners and an increase in Group\u2019s
long-term oil price assumption, resulting in an increase in
Carrying value of intangible exploration and evaluation assets (note 9) the underlying value of the project. Due to the stage of this project being pre-final 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 profiles and certain fiscal terms. Furthermore, the Group has identified 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 financing for the project and government deliverables in form of provision of required infrastructure and fiscal terms. 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 flows 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 an impairment charge of $17.9 million was booked as at 31 December 2023. 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 additional impairment of $242.2 million. (af) 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 significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below. Carrying value of property, plant and equipment (note 9) 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 flows 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 profiles. 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 191). The estimation applied by management to the exploration risk premium adjustment to its impairment discount rates, estimated future commodity prices and forecast cash flows on the TEN asset would have the most material impact on the 2023 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 9. Lease accounting (note 18) 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 at the lease commencement date if the interest rate implicit in the lease is not readily determinable. For the material remeasurements during the year, predominantly on the TEN FPSO lease discussed in note 18 the Group has assessed the incremental borrowing rate to be 16.88%. 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 flexibility 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. In respect of the TEN FPSO lease, the lease term was updated to reflect the management\u2019s best estimate view that the FPSO will continue to be leased until the cessation of production in 2032 and assumes an exercise of the extension option following a decision not to exercise the purchase option. 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 financial impact based on external tax and legal advice and prior experience of such claims. Provisions of $85.0 million (2022: $106.4 million) are included in income tax payable ($78.3 million (2022: $70.6 million)), deferred tax liability ($nil (2022: $nil)), and provisions ($6.7 million (2022: $35.8 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. 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 significantly from management\u2019s estimate. If the Group was unsuccessful in defending itself from all of these claims, the result would be additional liabilities of $1,030.3 million (2022: $1,024.0 million) which includes $6.9 million of interest and penalties (2022: $32.4 million). 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 2023, giving rise to an overall decrease in provision of $21.4 million and increase in contingent liability of $6.2 million. Ghana tax assessments In October 2021, Tullow Ghana Limited (TGL) filed a Request for Arbitration with the International Chamber of Commerce (ICC) disputing the $320.3 million branch profits remittance tax (BPRT) assessment issued as part of the direct tax audit for the financial 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 arbitration hearing took place in October 2023 and a decision is expected in the current financial year. TGL is not required to pay any amounts of BPRT until the dispute is formally resolved. 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 financial 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 filed 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. The arbitration hearing is scheduled to commence on 30 June 2025. 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 financial 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 filed 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 arbitration hearing is scheduled to commence on 17 November 2025. The Group continues to engage with the Government of Ghana with the aim of resolving the BPRT, loan interest and insurance disputes on a mutually acceptable basis. Bangladesh litigation The National Board of Revenue (NBR) is seeking to disallow $118.6 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 3,094.3 million (c.$29.3 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 first submissions have been made in October 2022 with counter submissions received on 17 January 2023. The second submission was made in June 2023 with the first Tribunal hearing scheduled for 20-24 May 2024. A decision is expected in H1 2025. Other items Other items totalling $294.0 million (2022: $280.0 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 flows While it is not possible to estimate the timing and amount of tax cash flows in relation to possible outcomes with certainty, as they are subject to outcome of court/ arbitration proceedings and any potential appeals, management anticipates that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments.", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-402": { "value": "(af) 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 significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below. Carrying value of property, plant and equipment (note 9) 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 flows 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 profiles. 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 191). The estimation applied by management to the exploration risk premium adjustment to its impairment discount rates, estimated future commodity prices and forecast cash flows on the TEN asset would have the most material impact on the 2023 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 9. Lease accounting (note 18) 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 at the lease commencement date if the interest rate implicit in the lease is not readily determinable. For the material remeasurements during the year, predominantly on the TEN FPSO lease discussed in note 18 the Group has assessed the incremental borrowing rate to be 16.88%. 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 flexibility 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. In respect of the TEN FPSO lease, the lease term was updated to reflect the management\u2019s best estimate view that the FPSO will continue to be leased until the cessation of production in 2032 and assumes an exercise of the extension option following a decision not to exercise the purchase option. 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 financial impact based on external tax and legal advice and prior experience of such claims. Provisions of $85.0 million (2022: $106.4 million) are included in income tax payable ($78.3 million (2022: $70.6 million)), deferred tax liability ($nil (2022: $nil)), and provisions ($6.7 million (2022: $35.8 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. 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 significantly from management\u2019s estimate. If the Group was unsuccessful in defending itself from all of these claims, the result would be additional liabilities of $1,030.3 million (2022: $1,024.0 million) which includes $6.9 million of interest and penalties (2022: $32.4 million). 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 2023, giving rise to an overall decrease in provision of $21.4 million and increase in contingent liability of $6.2 million. Ghana tax assessments In October 2021, Tullow Ghana Limited (TGL) filed a Request for Arbitration with the International Chamber of Commerce (ICC) disputing the $320.3 million branch profits remittance tax (BPRT) assessment issued as part of the direct tax audit for the financial 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 arbitration hearing took place in October 2023 and a decision is expected in the current financial year. TGL is not required to pay any amounts of BPRT until the dispute is formally resolved. 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 financial 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 filed 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. The arbitration hearing is scheduled to commence on 30 June 2025. 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 financial 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 filed 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 arbitration hearing is scheduled to commence on 17 November 2025. The Group continues to engage with the Government of Ghana with the aim of resolving the BPRT, loan interest and insurance disputes on a mutually acceptable basis. Bangladesh litigation The National Board of Revenue (NBR) is seeking to disallow $118.6 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 3,094.3 million (c.$29.3 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 first submissions have been made in October 2022 with counter submissions received on 17 January 2023. The second submission was made in June 2023 with the first Tribunal hearing scheduled for 20-24 May 2024. A decision is expected in H1 2025. Other items Other items totalling $294.0 million (2022: $280.0 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 flows While it is not possible to estimate the timing and amount of tax cash flows in relation to possible outcomes with certainty, as they are subject to outcome of court/ arbitration proceedings and any potential appeals, management anticipates that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments.", "dimensions": { "concept": "ifrs-full:ExplanationOfAssumptionAboutFutureWithSignificantRiskOfResultingInMaterialAdjustments", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-357": { "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 2023 and 31 December 2022.
Non-
Ghana Operated Kenya Exploration Corporate Total
$m $m $m $m $m $m
2023
Sales revenue by origin
1,311.4
461.8
\u2013
\u2013
(139.1)
1,634.1
Segment result
408.2
114.0
(17.9)
(9.9)
(164.6)
329.8
Provisions reversal
22.0
Other gains
0.2
Unallocated corporate expenses (56.1)
Operating profit
295.9
Loss on hedging instruments
(0.4)
Gain on bond buyback
86.0
Finance income
44.0
Finance costs
(329.6)
Profit before tax
95.9
Income tax expense
(205.5)
Loss after tax
(109.6)
Total assets
3,529.7
200.9
253.3
48.5
426.2
4,458.6
Total liabilities
(2,231.6)
(355.1)
(10.3)
(2.9)
(2,218.1)
(4,818.0)
Other segment information
Capital expenditure:
Property, plant and equipment
413.7
85.9
(2.2)
\u2013
2.1
499.5
Intangible exploration and evaluation assets
0.2
1.6
7.5
16.1
\u2013
25.4
Depletion, depreciation and amortisation
(387.7)
(44.1)
0.6
\u2013
(5.4)
(436.6)
Impairment of property, plant and equipment, net
(301.2)
(97.9)
\u2013
\u2013
(9.0)
(408.1)
Exploration costs written off
(0.2)
0.9
(17.9)
(9.8)
\u2013
(27.0)
1
2
3
1. Segment result is a non-IFRS measure which includes gross profit, exploration costs written off and impairment of property, plant and equipment. See
reconciliation below.
2. Unallocated expenditure includes amounts of a corporate nature and not specifically attributable to a geographic area.
3. Total liabilities \u2013 Corporate comprise the Group\u2019s external debt and other non-attributable liabilities.
Reconciliation of segment result
2023 2022
$m $m
Segment result
329.8
589.2
Add back:
Exploration costs written off
27.0
105.2
Impairment of property, plant and equipment
408.1
391.2
Gross profit
764.9
1,085.6
All sales are made to external customers. Included in revenue arising from Ghana and Non-Operated segments are
revenues of approximately $462.3 million, $326.9 million and $181.9 million relating to the Group\u2019s customers who each
contribute more than 10% of total sales revenue (2022: $696.9 million, $566.1 million, $310.9 million and $242.3 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.
During 2023, Tullow has entered into an oil marketing contract under which it will sell its crude oil entitlements to
Glencore Energy UK Limited. The contract expires in 2028.
Non-
Ghana Operated Kenya Exploration Corporate Total
$m $m $m $m $m $m
2022
Sales revenue by origin
1,578.5
524.0
\u2013
\u2013
(319.4)
1,783.1
Segment result
692.5
337.3
(0.5)
(102.6)
(337.5)
589.2
Provisions expense
(4.1)
Gain on bargain purchase
196.8
Other gains
3.1
Unallocated corporate expenses (51.1)
Operating profit
733.9
Gain on hedging instruments
0.8
Finance income
42.9
Finance costs
(335.5)
Profit before tax
442.1
Income tax expense
(393.0)
Profit after tax
49.1
Total assets
3,827.7
380.6
265.6
46.0
519.7
5,039.6
Total liabilities
(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
2
3
1. Segment result is a non-IFRS measure which includes gross profit, exploration costs written off and impairment of property, plant and equipment. See
reconciliation below.
2. Unallocated expenditure includes amounts of a corporate nature and not specifically attributable to a geographic area.
3. Total liabilities \u2013 Corporate comprise the Group\u2019s external debt and other non-attributable liabilities.
Non- Non-
Sales Sales current current
revenue revenue
assets
1
assets
1
2023 2022 2023 2022
Sales revenue and non-current assets by origin $m $m $m $m
Ghana
1,311.4
1,578.5
2,771.0
3,087.4
Total Ghana
1,311.4
1,578.5
2,771.0
3,087.4
Kenya
\u2013
\u2013
250.0
258.5
Total Kenya
\u2013
\u2013
250.0
258.5
Argentina
\u2013
\u2013
36.4
33.6
C\u00f4te d\u2019Ivoire
\u2013
\u2013
5.8
2.4
Total Exploration
\u2013
\u2013
42.2
36.0
Gabon
419.5
477.0
82.8
132.6
C\u00f4te d\u2019Ivoire
42.3
47.0
0.4
59.2
Total Non-Operated
461.8
524.0
83.2
191.8
Corporate
(139.1)
(319.4)
12.0
23.4
Total
1,634.1
1,783.1
3,158.4
3,597.1
1. Non-current assets exclude derivative financial instruments and deferred tax assets.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-403": { "value": "
Non- Non-
Sales Sales current current
revenue revenue
assets
1
assets
1
2023 2022 2023 2022
Sales revenue and non-current assets by origin $m $m $m $m
Ghana
1,311.4
1,578.5
2,771.0
3,087.4
Total Ghana
1,311.4
1,578.5
2,771.0
3,087.4
Kenya
\u2013
\u2013
250.0
258.5
Total Kenya
\u2013
\u2013
250.0
258.5
Argentina
\u2013
\u2013
36.4
33.6
C\u00f4te d\u2019Ivoire
\u2013
\u2013
5.8
2.4
Total Exploration
\u2013
\u2013
42.2
36.0
Gabon
419.5
477.0
82.8
132.6
C\u00f4te d\u2019Ivoire
42.3
47.0
0.4
59.2
Total Non-Operated
461.8
524.0
83.2
191.8
Corporate
(139.1)
(319.4)
12.0
23.4
Total
1,634.1
1,783.1
3,158.4
3,597.1
1. Non-current assets exclude derivative financial instruments and deferred tax assets.", "dimensions": { "concept": "ifrs-full:DisclosureOfGeographicalAreasExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-358": { "value": "
Note 2. Total revenue
2023 2022
$m $m
Revenue from contracts with customers
Revenue from crude oil sales
1,744.6
2,102.5
Revenue from gas sales
28.6
\u2013
Total revenue from contracts with customers
1,773.2
2,102.5
Loss on realisation of cash flow hedges
(139.1)
(319.4)
Total revenue
1,634.1
1,783.1
Finance income has been presented as part of net financing costs (refer to note 5).
", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-404": { "value": "Note 2. Total revenue
2023 2022
$m $m
Revenue from contracts with customers
Revenue from crude oil sales
1,744.6
2,102.5
Revenue from gas sales
28.6
\u2013
Total revenue from contracts with customers
1,773.2
2,102.5
Loss on realisation of cash flow hedges
(139.1)
(319.4)
Total revenue
1,634.1
1,783.1
Finance income has been presented as part of net financing costs (refer to note 5).", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-359": { "value": "
Note 3. Staff costs
The average annual number of employees employed by the Group worldwide was:
2023 2022
Number Number
Administration
187
182
Technical
206
194
Total
393
376
Staff costs in respect of those employees were as follows:
2023 2022
$m $m
Salaries
71.5
66.3
Social security costs
7.1
7.0
Pension costs
6.3
5.3
Redundancy costs
\u2013
0.1
Total staff costs
84.9
78.7
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 fixed assets under the Group\u2019s accounting
policy for exploration, evaluation and production assets with the remainder classified as an administrative overhead cost
in the income statement. The net staff costs recognised in the income statement were $16.5 million (2022: $10.5 million).
The Group operates defined 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
$6.3 million (2022: $5.3 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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-360": { "value": "
Note 4. Other costs
2023 2022
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
292.9
266.5
Depletion and amortisation of oil and gas and leased assets
9
430.8
410.7
Overlift, underlift and oil stock movements
109.3
(46.3)
Royalties
33.9
61.7
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
1.9
4.4
Total cost of sales
869.2
697.5
Share-based payment charge included in administrative expenses
22
5.6
5.4
Depreciation of other fixed assets
9
5.8
15.1
Other administrative costs
44.7
30.5
Total administrative expenses
56.1
51.0
Provisions (reversal)/ expense
(22.0)
4.2
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.0
2.1
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.6
Total audit services
2.5
2.7
Non-audit services:
Audit-related assurance services \u2013 half-year review
0.5
0.5
Corporate finance services
\u2013
1.0
Total non-audit services
0.5
1.5
Total
3.0
4.2
1
1
2
1. Depreciation expense on leased assets of $81.4 million (2022: $60.9 million) as per note 9 includes a charge of $2.2 million ($3.9 million) on leased
administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $79.2 million (2022: $57.0
million) relates to other leased assets and is included within cost of sales.
The reduction in depreciation of other fixed assets expense is caused by corporate assets in the UK and Ghana reaching the end of their useful life
during 2022 and 2023.
2. This includes credit to the movements in other provisions of $22.0 million (2022: $4.1 million charge) as well as restructuring and redundancy costs of
$nil (2022: $0.1 million).
The increase in other administrative costs is mainly due to one-off corporate project expenditure which was partially offset by lower insurance premiums in the current year. 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. Non-audit services were 20% 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 82 to 86. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-446": { "value": "Note 4. Other costs
2023 2022
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
292.9
266.5
Depletion and amortisation of oil and gas and leased assets
9
430.8
410.7
Overlift, underlift and oil stock movements
109.3
(46.3)
Royalties
33.9
61.7
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
1.9
4.4
Total cost of sales
869.2
697.5
Share-based payment charge included in administrative expenses
22
5.6
5.4
Depreciation of other fixed assets
9
5.8
15.1
Other administrative costs
44.7
30.5
Total administrative expenses
56.1
51.0
Provisions (reversal)/ expense
(22.0)
4.2
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.0
2.1
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.6
Total audit services
2.5
2.7
Non-audit services:
Audit-related assurance services \u2013 half-year review
0.5
0.5
Corporate finance services
\u2013
1.0
Total non-audit services
0.5
1.5
Total
3.0
4.2
1 1 2 1. Depreciation expense on leased assets of $81.4 million (2022: $60.9 million) as per note 9 includes a charge of $2.2 million ($3.9 million) on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $79.2 million (2022: $57.0 million) relates to other leased assets and is included within cost of sales. The reduction in depreciation of other fixed assets expense is caused by corporate assets in the UK and Ghana reaching the end of their useful life during 2022 and 2023. 2. This includes credit to the movements in other provisions of $22.0 million (2022: $4.1 million charge) as well as restructuring and redundancy costs of $nil (2022: $0.1 million). The increase in other administrative costs is mainly due to one-off corporate project expenditure which was partially offset by lower insurance premiums in the current year. 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. Non-audit services were 20% 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 82 to 86. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-433": { "value": "Note 4. Other costs
2023 2022
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
292.9
266.5
Depletion and amortisation of oil and gas and leased assets
9
430.8
410.7
Overlift, underlift and oil stock movements
109.3
(46.3)
Royalties
33.9
61.7
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
1.9
4.4
Total cost of sales
869.2
697.5
Share-based payment charge included in administrative expenses
22
5.6
5.4
Depreciation of other fixed assets
9
5.8
15.1
Other administrative costs
44.7
30.5
Total administrative expenses
56.1
51.0
Provisions (reversal)/ expense
(22.0)
4.2
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.0
2.1
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.6
Total audit services
2.5
2.7
Non-audit services:
Audit-related assurance services \u2013 half-year review
0.5
0.5
Corporate finance services
\u2013
1.0
Total non-audit services
0.5
1.5
Total
3.0
4.2
1 1 2 1. Depreciation expense on leased assets of $81.4 million (2022: $60.9 million) as per note 9 includes a charge of $2.2 million ($3.9 million) on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $79.2 million (2022: $57.0 million) relates to other leased assets and is included within cost of sales. The reduction in depreciation of other fixed assets expense is caused by corporate assets in the UK and Ghana reaching the end of their useful life during 2022 and 2023. 2. This includes credit to the movements in other provisions of $22.0 million (2022: $4.1 million charge) as well as restructuring and redundancy costs of $nil (2022: $0.1 million). The increase in other administrative costs is mainly due to one-off corporate project expenditure which was partially offset by lower insurance premiums in the current year. 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. Non-audit services were 20% 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 82 to 86. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-405": { "value": "Note 4. Other costs
2023 2022
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
292.9
266.5
Depletion and amortisation of oil and gas and leased assets
9
430.8
410.7
Overlift, underlift and oil stock movements
109.3
(46.3)
Royalties
33.9
61.7
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
1.9
4.4
Total cost of sales
869.2
697.5
Share-based payment charge included in administrative expenses
22
5.6
5.4
Depreciation of other fixed assets
9
5.8
15.1
Other administrative costs
44.7
30.5
Total administrative expenses
56.1
51.0
Provisions (reversal)/ expense
(22.0)
4.2
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.0
2.1
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.6
Total audit services
2.5
2.7
Non-audit services:
Audit-related assurance services \u2013 half-year review
0.5
0.5
Corporate finance services
\u2013
1.0
Total non-audit services
0.5
1.5
Total
3.0
4.2
1 1 2 1. Depreciation expense on leased assets of $81.4 million (2022: $60.9 million) as per note 9 includes a charge of $2.2 million ($3.9 million) on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $79.2 million (2022: $57.0 million) relates to other leased assets and is included within cost of sales. The reduction in depreciation of other fixed assets expense is caused by corporate assets in the UK and Ghana reaching the end of their useful life during 2022 and 2023. 2. This includes credit to the movements in other provisions of $22.0 million (2022: $4.1 million charge) as well as restructuring and redundancy costs of $nil (2022: $0.1 million).
The increase in other administrative costs is mainly due to one-off corporate project expenditure which was partially
offset by lower insurance premiums in the current year.
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.
Non-audit services were 20% 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 82 to 86. No services were provided pursuant to contingent fee arrangements.
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-453": { "value": "
2023 2022
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
292.9
266.5
Depletion and amortisation of oil and gas and leased assets
9
430.8
410.7
Overlift, underlift and oil stock movements
109.3
(46.3)
Royalties
33.9
61.7
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
1.9
4.4
Total cost of sales
869.2
697.5
Share-based payment charge included in administrative expenses
22
5.6
5.4
Depreciation of other fixed assets
9
5.8
15.1
Other administrative costs
44.7
30.5
Total administrative expenses
56.1
51.0
Provisions (reversal)/ expense
(22.0)
4.2
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.0
2.1
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.6
Total audit services
2.5
2.7
Non-audit services:
Audit-related assurance services \u2013 half-year review
0.5
0.5
Corporate finance services
\u2013
1.0
Total non-audit services
0.5
1.5
Total
3.0
4.2
1 1 2 1. Depreciation expense on leased assets of $81.4 million (2022: $60.9 million) as per note 9 includes a charge of $2.2 million ($3.9 million) on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $79.2 million (2022: $57.0 million) relates to other leased assets and is included within cost of sales. The reduction in depreciation of other fixed assets expense is caused by corporate assets in the UK and Ghana reaching the end of their useful life during 2022 and 2023. 2. This includes credit to the movements in other provisions of $22.0 million (2022: $4.1 million charge) as well as restructuring and redundancy costs of $nil (2022: $0.1 million). ", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-458": { "value": "
2023 2022
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
292.9
266.5
Depletion and amortisation of oil and gas and leased assets
9
430.8
410.7
Overlift, underlift and oil stock movements
109.3
(46.3)
Royalties
33.9
61.7
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
1.9
4.4
Total cost of sales
869.2
697.5
Share-based payment charge included in administrative expenses
22
5.6
5.4
Depreciation of other fixed assets
9
5.8
15.1
Other administrative costs
44.7
30.5
Total administrative expenses
56.1
51.0
Provisions (reversal)/ expense
(22.0)
4.2
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.0
2.1
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.6
Total audit services
2.5
2.7
Non-audit services:
Audit-related assurance services \u2013 half-year review
0.5
0.5
Corporate finance services
\u2013
1.0
Total non-audit services
0.5
1.5
Total
3.0
4.2
1 1 2 1. Depreciation expense on leased assets of $81.4 million (2022: $60.9 million) as per note 9 includes a charge of $2.2 million ($3.9 million) on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $79.2 million (2022: $57.0 million) relates to other leased assets and is included within cost of sales. The reduction in depreciation of other fixed assets expense is caused by corporate assets in the UK and Ghana reaching the end of their useful life during 2022 and 2023. 2. This includes credit to the movements in other provisions of $22.0 million (2022: $4.1 million charge) as well as restructuring and redundancy costs of $nil (2022: $0.1 million). ", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-462": { "value": "
2023 2022
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
292.9
266.5
Depletion and amortisation of oil and gas and leased assets
9
430.8
410.7
Overlift, underlift and oil stock movements
109.3
(46.3)
Royalties
33.9
61.7
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
1.9
4.4
Total cost of sales
869.2
697.5
Share-based payment charge included in administrative expenses
22
5.6
5.4
Depreciation of other fixed assets
9
5.8
15.1
Other administrative costs
44.7
30.5
Total administrative expenses
56.1
51.0
Provisions (reversal)/ expense
(22.0)
4.2
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.0
2.1
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.6
Total audit services
2.5
2.7
Non-audit services:
Audit-related assurance services \u2013 half-year review
0.5
0.5
Corporate finance services
\u2013
1.0
Total non-audit services
0.5
1.5
Total
3.0
4.2
1 1 2 1. Depreciation expense on leased assets of $81.4 million (2022: $60.9 million) as per note 9 includes a charge of $2.2 million ($3.9 million) on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $79.2 million (2022: $57.0 million) relates to other leased assets and is included within cost of sales. The reduction in depreciation of other fixed assets expense is caused by corporate assets in the UK and Ghana reaching the end of their useful life during 2022 and 2023. 2. This includes credit to the movements in other provisions of $22.0 million (2022: $4.1 million charge) as well as restructuring and redundancy costs of $nil (2022: $0.1 million). ", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-361": { "value": "
Note 5. Net financing costs
2023 2022
Notes $m $m
Interest on bank overdrafts and borrowings
237.0
250.4
Interest on obligations under leases
18
78.6
76.4
Total borrowing costs
315.6
326.8
Finance and arrangement fees
1.9
0.3
Other interest expense
2.0
2.4
Unwinding of discount on decommissioning provisions
19
10.1
6.0
Total finance costs
329.6
335.5
Interest income on amounts due from Joint Venture Partners for leases
18
(30.1)
(29.6)
Other finance income
(13.9)
(13.3)
Total finance income
(44.0)
(42.9)
Net financing costs
285.6
292.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-459": { "value": "Note 5. Net financing costs
2023 2022
Notes $m $m
Interest on bank overdrafts and borrowings
237.0
250.4
Interest on obligations under leases
18
78.6
76.4
Total borrowing costs
315.6
326.8
Finance and arrangement fees
1.9
0.3
Other interest expense
2.0
2.4
Unwinding of discount on decommissioning provisions
19
10.1
6.0
Total finance costs
329.6
335.5
Interest income on amounts due from Joint Venture Partners for leases
18
(30.1)
(29.6)
Other finance income
(13.9)
(13.3)
Total finance income
(44.0)
(42.9)
Net financing costs
285.6
292.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-454": { "value": "Note 5. Net financing costs
2023 2022
Notes $m $m
Interest on bank overdrafts and borrowings
237.0
250.4
Interest on obligations under leases
18
78.6
76.4
Total borrowing costs
315.6
326.8
Finance and arrangement fees
1.9
0.3
Other interest expense
2.0
2.4
Unwinding of discount on decommissioning provisions
19
10.1
6.0
Total finance costs
329.6
335.5
Interest income on amounts due from Joint Venture Partners for leases
18
(30.1)
(29.6)
Other finance income
(13.9)
(13.3)
Total finance income
(44.0)
(42.9)
Net financing costs
285.6
292.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-447": { "value": "Note 5. Net financing costs
2023 2022
Notes $m $m
Interest on bank overdrafts and borrowings
237.0
250.4
Interest on obligations under leases
18
78.6
76.4
Total borrowing costs
315.6
326.8
Finance and arrangement fees
1.9
0.3
Other interest expense
2.0
2.4
Unwinding of discount on decommissioning provisions
19
10.1
6.0
Total finance costs
329.6
335.5
Interest income on amounts due from Joint Venture Partners for leases
18
(30.1)
(29.6)
Other finance income
(13.9)
(13.3)
Total finance income
(44.0)
(42.9)
Net financing costs
285.6
292.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-434": { "value": "Note 5. Net financing costs
2023 2022
Notes $m $m
Interest on bank overdrafts and borrowings
237.0
250.4
Interest on obligations under leases
18
78.6
76.4
Total borrowing costs
315.6
326.8
Finance and arrangement fees
1.9
0.3
Other interest expense
2.0
2.4
Unwinding of discount on decommissioning provisions
19
10.1
6.0
Total finance costs
329.6
335.5
Interest income on amounts due from Joint Venture Partners for leases
18
(30.1)
(29.6)
Other finance income
(13.9)
(13.3)
Total finance income
(44.0)
(42.9)
Net financing costs
285.6
292.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-406": { "value": "Note 5. Net financing costs
2023 2022
Notes $m $m
Interest on bank overdrafts and borrowings
237.0
250.4
Interest on obligations under leases
18
78.6
76.4
Total borrowing costs
315.6
326.8
Finance and arrangement fees
1.9
0.3
Other interest expense
2.0
2.4
Unwinding of discount on decommissioning provisions
19
10.1
6.0
Total finance costs
329.6
335.5
Interest income on amounts due from Joint Venture Partners for leases
18
(30.1)
(29.6)
Other finance income
(13.9)
(13.3)
Total finance income
(44.0)
(42.9)
Net financing costs
285.6
292.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-362": { "value": "
Note 6. Taxation on profit on continuing activities
2023 2022
Notes $m $m
Current tax on profits for the year
UK corporation tax
(1.9)
(11.8)
Foreign tax
322.2
321.0
Taxes paid in kind under production sharing contracts
11.0
21.4
Adjustments in respect of prior periods
(10.8)
(3.3)
Total corporate tax
342.1
327.3
UK petroleum revenue tax
(0.7)
(2.8)
Total current tax
341.4
324.5
Deferred tax
Origination and reversal of temporary differences
UK corporation tax
(22.9)
11.4
Foreign tax
(106.5)
54.0
Adjustments in respect of prior periods
(2.8)
(2.9)
Total deferred corporate tax
(132.2)
62.5
Deferred UK petroleum revenue tax
(3.7)
6.0
Total deferred tax
20
(135.9)
68.5
Total income tax expense
205.5
393.0
The tax rate applied to profit on continuing activities in preparing the reconciliation below is the UK corporation tax rate
applicable to the Group\u2019s UK profits, being 23.5% (2022: 19%), which is the weighted average rate calculated for FY 2023
taking into account the UK CT rate change effective from 1 April 2023. 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
profits of 23.5% is as follows:
2023 2022
$m $m
Profit from continuing activities before tax
95.9
442.1
Tax on profit from continuing activities at the standard UK corporation tax rate of 23.5% (2022: 19%)
22.5
84.0
Effects of:
Non-deductible exploration expenditure
3.4
0.5
Other non-deductible expenses
35.4
27.8
Net deferred tax asset not recognised
65.1
138.5
Utilisation of tax losses not previously recognised
(0.2)
(0.4)
Adjustment relating to prior years
(2.8)
(6.2)
Other tax rates applicable outside the UK
82.4
214.6
Other income not subject to corporation tax
(0.3)
(0.1)
Tax impact of acquisition through business combination
\u2013
(65.7)
Total income tax expense for the year
205.5
393.0
a
b,d
c
a. Includes recurring explorations costs written off where there is no deferred tax impact.
b. Includes impairments.
c. Includes hedging losses and interest expense.
d. Includes movements in provisions in respect of uncertain tax treatments.
The Group\u2019s profit 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 fields (50%), Gabon PSC fields (35%) and CDI PSC (25%).
Furthermore, there is no tax benefit 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 profits arise.
The Group has tax losses of $4,195.3 million (2022: $4,237.4 million) of which $3,109.9 million are available for offset
indefinitely and $1,085.4 million in the next 5-7 years against future taxable profits in the companies in which the losses
arose. Deferred tax assets have not been recognised in respect of losses of $4,165.7 million (2022: $4,128.9 million) as it is
not sufficiently probable that there will be future taxable profits against which these losses can be utilised.
The Group has recognised deferred tax assets of $7.4 million (2022: $35.8 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 indefinitely.
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 2023 nil tax expense (2022: nil tax expense) has been recognised through other comprehensive income.
Global minimum top-up tax
The Group operates in the UK, which has enacted new legislation to implement the global minimum top-up tax. However,
since the newly enacted tax legislation is only effective from 1 January 2024, there is no current tax impact for the year
ended 31 December 2023. The Group is not expecting to pay top-up taxes in the future because all jurisdictions in
which the Group operates are above 15% and management is not currently aware of any circumstances under which this
might change.
The Group has applied a temporary mandatory relief from deferred tax accounting for the impacts of the top-up tax and
accounts for it as a current tax when it is incurred.
Note 20. Deferred taxation
Accelerated Other Deferred
tax Decommiss- Tax temporary petroleum
depreciation ioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
(143.6)
\u2013
\u2013
\u2013
\u2013
\u2013
(143.6)
Exchange differences
(0.2)
\u2013
\u2013
\u2013
\u2013
(1.8)
(2.0)
At 1 January 2023
(558.1)
65.9
35.8
(99.0)
15.8
2.6
(537.0)
Credit/(charge) to income statement
117.9
1.7
(28.4)
40.9
\u2013
3.8
135.9
Exchange differences
\u2013
\u2013
\u2013
\u2013
\u2013
0.2
0.2
At 31 December 2023
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
1
2023 2022
$m $m
Deferred tax liabilities
(420.5)
(551.5)
Deferred tax assets
19.6
14.5
(400.9)
(537.0)
1. This relates to an acquisition through business combination discussed in note 15 of the 2022 Annual Report and Accounts.
The majority of the Group\u2019s 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 profits available to offset the tax assets when they do reverse. This requires assumptions
regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability
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:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-364": { "value": "
Note 7. (Loss)/earnings per ordinary share
Basic (loss)/earnings per ordinary share amounts are calculated by dividing net (loss)/ profit 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 (loss)/ profit 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.
2023 2022
$m $m
(Loss)/ pro\ue01fit for the year
Net (loss)/profit attributable to equity shareholders
(109.6)
49.1
Effect of dilutive potential ordinary shares
\u2013
\u2013
Diluted net (loss)/ earnings attributable to equity shareholders
(109.6)
49.1
2023 2022
Number Number
Number of shares
Basic weighted average number of shares
1,447,121,945
1,437,099,966
Dilutive potential ordinary shares
\u2013
48,375,409
Diluted weighted average number of shares
1,447,121,945
1,485,475,375
", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-363": { "value": "
Note 8. Intangible exploration and evaluation assets
2023 2022
$m $m
At 1 January
288.6
354.6
Additions
25.4
39.2
Amounts written off
(27.0)
(105.2)
At 31 December
287.0
288.6
The below table provides a summary of the exploration costs written off on a pre-tax basis by country.
2023
2023 Remaining
Rationale for write-off/ recoverable
2023 (back) amount
Country
CGU
write-off $m $m
Guyana
Kanuku
a
1.7
\u2013
Guyana
Orinduik
a
0.7
\u2013
C\u00f4te d\u2019Ivoire
Block 524
a
3.3
\u2013
Kenya
Blocks 10BB and 13T
b, c
17.9
242.2
New Ventures
Various
d
4.1
\u2013
Uganda
Exploration areas 1, 1A, 2 and 3A
e
(4.3)
\u2013
Gabon
DE8
f
3.4
\u2013
Other
Various
0.2
\u2013
Total write-off
27.0
\u2013
a. Current-year expenditure on assets previously written off.
b. Following VIU assessment subsequent to withdrawal of JV Partners.
c. Revision of short, medium and long-term oil price assumptions.
d. New Ventures expenditure is written off as incurred.
e. Release of indirect tax provision following settlement.
f. Unsuccessful well costs written off.
Kenya
Discussions with the Government of Kenya (GoK) on securing government deliverables and approval of the Field
Development Plan (FDP) have been ongoing since its submission on 10 December 2021. An updated FDP was submitted
on 3 March 2023 and is being reviewed by the GoK before ratification by the Kenyan Parliament. Energy and Petroleum
Regulatory Authority (EPRA), the regulator, has engaged third party consultants to review the revised FDP and the current
review period ends on 30 June 2024. The Group expects a production licence to be granted once government due
process has been completed.
On 22 May 2023, Africa Oil Corporation (AOC) and Total Energies (TE) gave notice of their respective withdrawal from the
Blocks 10BA, 10BB and 13T Production Sharing Contracts (PSCs) and the Joint Operating Agreements (JOAs), effective
30 June 2023, quoting differing internal strategic objectives as reasons. The withdrawal is ultimately subject to the GoK\u2019s
consent, at which stage the transaction will be considered completed and Tullow will have full rights and liabilities under
the JOA. Pending GoK approval, per the terms of the agreement, the participating interest (PI) vests in trust for the sole
and exclusive benefit of Tullow, who is the only remaining Joint Venture Partner.
In management\u2019s view, in light of public statements and announcements made by AOC and TE to this effect, and in
accordance with the terms of the Joint Operating Agreement, it is considered that the ownership of the 50% held by
AOC and TE was passed on 30 June 2023, resulting in Tullow holding 100%. From that date, Tullow has the right to benefit
from the PI and is liable for all costs incurred going forward (except those for which the withdrawing parties remain
liable for). As the sole party, Tullow can control and direct the use of the asset from 30 June 2023. The position remained
unchanged as at 31 December 2023. Tullow accounted for this as an asset acquisition at nil cost.
The withdrawal of the partners and an upward revision to the Group\u2019s oil prices as detailed in note 9 are considered to be
impairment assessment triggers for the asset as at 31 December 2023, and in line with its accounting policy the Group
has performed a VIU assessment. The cash flows were discounted using a pre-tax nominal discount rate of 20% (2022:
20%). This resulted in an NPV significantly in excess of the book value of $260.1 million. However, the Group has identified
the following uncertainties in respect of the Group\u2019s ability to realise the estimated VIU; receiving and subsequently
finalising an acceptable offer from a strategic partner and securing governmental approvals relating thereto, obtaining
financing for the project and government deliverables in form of provision of required infrastructure and fiscal terms.
These items require satisfactory resolution before the Group can take a Final Investment Decision (FID). The Group
continues to progress with the farm-down process.
Due to the binary nature of these uncertainties the Group was unable to either adjust the cash flows 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. Certain risks have increased since 31 December 2022, predominantly
around farm-down and project financing. This has been partially offset by an increased equity interest in the project and
changes in oil price assumptions.
Based on this, the NPV has been revised to $242.2 million and an impairment of $17.9 million has been recognised as at
31 December 2023.
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 $242.2 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 specified above would increase the impairment charge by $37.9 million, whilst increases
to oil prices specified above would result in a credit to the impairment charge of $37.7 million. A 1% change in the pre-
tax discount rate would result in an additional impairment charge of $33.9 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.
For Net Zero Emissions sensitivities refer to page 45 of the TCFD.
Guyana
On 10 August 2023, Tullow announced that it had agreed to sell its total interest in Tullow Guyana B.V., which includes
the Orinduik licence (60% operated equity) in Guyana, to Eco Guyana Oil and Gas (Barbados) Limited in exchange for an
upfront cash consideration of $0.7 million and contingent consideration linked to a series of potential future milestones.
The transaction completed on 16 November 2023 and resulted in $0.7 million of gain on disposal included in Other gains
the income statement.
2022
Remaining
Rationale for 2022 recoverable
2022 write-off amount
Country
CGU
write-off $m $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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-435": { "value": "Note 8. Intangible exploration and evaluation assets
2023 2022
$m $m
At 1 January
288.6
354.6
Additions
25.4
39.2
Amounts written off
(27.0)
(105.2)
At 31 December
287.0
288.6
The below table provides a summary of the exploration costs written off on a pre-tax basis by country.
2023
2023 Remaining
Rationale for write-off/ recoverable
2023 (back) amount
Country
CGU
write-off $m $m
Guyana
Kanuku
a
1.7
\u2013
Guyana
Orinduik
a
0.7
\u2013
C\u00f4te d\u2019Ivoire
Block 524
a
3.3
\u2013
Kenya
Blocks 10BB and 13T
b, c
17.9
242.2
New Ventures
Various
d
4.1
\u2013
Uganda
Exploration areas 1, 1A, 2 and 3A
e
(4.3)
\u2013
Gabon
DE8
f
3.4
\u2013
Other
Various
0.2
\u2013
Total write-off
27.0
\u2013
a. Current-year expenditure on assets previously written off. b. Following VIU assessment subsequent to withdrawal of JV Partners. c. Revision of short, medium and long-term oil price assumptions. d. New Ventures expenditure is written off as incurred. e. Release of indirect tax provision following settlement. f. Unsuccessful well costs written off. Kenya Discussions with the Government of Kenya (GoK) on securing government deliverables and approval of the Field Development Plan (FDP) have been ongoing since its submission on 10 December 2021. An updated FDP was submitted on 3 March 2023 and is being reviewed by the GoK before ratification by the Kenyan Parliament. Energy and Petroleum Regulatory Authority (EPRA), the regulator, has engaged third party consultants to review the revised FDP and the current review period ends on 30 June 2024. The Group expects a production licence to be granted once government due process has been completed. On 22 May 2023, Africa Oil Corporation (AOC) and Total Energies (TE) gave notice of their respective withdrawal from the Blocks 10BA, 10BB and 13T Production Sharing Contracts (PSCs) and the Joint Operating Agreements (JOAs), effective 30 June 2023, quoting differing internal strategic objectives as reasons. The withdrawal is ultimately subject to the GoK\u2019s consent, at which stage the transaction will be considered completed and Tullow will have full rights and liabilities under the JOA. Pending GoK approval, per the terms of the agreement, the participating interest (PI) vests in trust for the sole and exclusive benefit of Tullow, who is the only remaining Joint Venture Partner. In management\u2019s view, in light of public statements and announcements made by AOC and TE to this effect, and in accordance with the terms of the Joint Operating Agreement, it is considered that the ownership of the 50% held by AOC and TE was passed on 30 June 2023, resulting in Tullow holding 100%. From that date, Tullow has the right to benefit from the PI and is liable for all costs incurred going forward (except those for which the withdrawing parties remain liable for). As the sole party, Tullow can control and direct the use of the asset from 30 June 2023. The position remained unchanged as at 31 December 2023. Tullow accounted for this as an asset acquisition at nil cost. The withdrawal of the partners and an upward revision to the Group\u2019s oil prices as detailed in note 9 are considered to be impairment assessment triggers for the asset as at 31 December 2023, and in line with its accounting policy the Group has performed a VIU assessment. The cash flows were discounted using a pre-tax nominal discount rate of 20% (2022: 20%). This resulted in an NPV significantly in excess of the book value of $260.1 million. However, the Group has identified the following uncertainties in respect of the Group\u2019s ability to realise the estimated VIU; receiving and subsequently finalising an acceptable offer from a strategic partner and securing governmental approvals relating thereto, obtaining financing for the project and government deliverables in form of provision of required infrastructure and fiscal terms. These items require satisfactory resolution before the Group can take a Final Investment Decision (FID). The Group continues to progress with the farm-down process. Due to the binary nature of these uncertainties the Group was unable to either adjust the cash flows 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. Certain risks have increased since 31 December 2022, predominantly around farm-down and project financing. This has been partially offset by an increased equity interest in the project and changes in oil price assumptions. Based on this, the NPV has been revised to $242.2 million and an impairment of $17.9 million has been recognised as at 31 December 2023. 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 $242.2 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 specified above would increase the impairment charge by $37.9 million, whilst increases to oil prices specified above would result in a credit to the impairment charge of $37.7 million. A 1% change in the pre- tax discount rate would result in an additional impairment charge of $33.9 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. For Net Zero Emissions sensitivities refer to page 45 of the TCFD. Guyana On 10 August 2023, Tullow announced that it had agreed to sell its total interest in Tullow Guyana B.V., which includes the Orinduik licence (60% operated equity) in Guyana, to Eco Guyana Oil and Gas (Barbados) Limited in exchange for an upfront cash consideration of $0.7 million and contingent consideration linked to a series of potential future milestones. The transaction completed on 16 November 2023 and resulted in $0.7 million of gain on disposal included in Other gains the income statement.
2022
Remaining
Rationale for 2022 recoverable
2022 write-off amount
Country
CGU
write-off $m $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.", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-407": { "value": "Note 8. Intangible exploration and evaluation assets
2023 2022
$m $m
At 1 January
288.6
354.6
Additions
25.4
39.2
Amounts written off
(27.0)
(105.2)
At 31 December
287.0
288.6
The below table provides a summary of the exploration costs written off on a pre-tax basis by country.
2023
2023 Remaining
Rationale for write-off/ recoverable
2023 (back) amount
Country
CGU
write-off $m $m
Guyana
Kanuku
a
1.7
\u2013
Guyana
Orinduik
a
0.7
\u2013
C\u00f4te d\u2019Ivoire
Block 524
a
3.3
\u2013
Kenya
Blocks 10BB and 13T
b, c
17.9
242.2
New Ventures
Various
d
4.1
\u2013
Uganda
Exploration areas 1, 1A, 2 and 3A
e
(4.3)
\u2013
Gabon
DE8
f
3.4
\u2013
Other
Various
0.2
\u2013
Total write-off
27.0
\u2013
a. Current-year expenditure on assets previously written off. b. Following VIU assessment subsequent to withdrawal of JV Partners. c. Revision of short, medium and long-term oil price assumptions. d. New Ventures expenditure is written off as incurred. e. Release of indirect tax provision following settlement. f. Unsuccessful well costs written off. Kenya Discussions with the Government of Kenya (GoK) on securing government deliverables and approval of the Field Development Plan (FDP) have been ongoing since its submission on 10 December 2021. An updated FDP was submitted on 3 March 2023 and is being reviewed by the GoK before ratification by the Kenyan Parliament. Energy and Petroleum Regulatory Authority (EPRA), the regulator, has engaged third party consultants to review the revised FDP and the current review period ends on 30 June 2024. The Group expects a production licence to be granted once government due process has been completed. On 22 May 2023, Africa Oil Corporation (AOC) and Total Energies (TE) gave notice of their respective withdrawal from the Blocks 10BA, 10BB and 13T Production Sharing Contracts (PSCs) and the Joint Operating Agreements (JOAs), effective 30 June 2023, quoting differing internal strategic objectives as reasons. The withdrawal is ultimately subject to the GoK\u2019s consent, at which stage the transaction will be considered completed and Tullow will have full rights and liabilities under the JOA. Pending GoK approval, per the terms of the agreement, the participating interest (PI) vests in trust for the sole and exclusive benefit of Tullow, who is the only remaining Joint Venture Partner. In management\u2019s view, in light of public statements and announcements made by AOC and TE to this effect, and in accordance with the terms of the Joint Operating Agreement, it is considered that the ownership of the 50% held by AOC and TE was passed on 30 June 2023, resulting in Tullow holding 100%. From that date, Tullow has the right to benefit from the PI and is liable for all costs incurred going forward (except those for which the withdrawing parties remain liable for). As the sole party, Tullow can control and direct the use of the asset from 30 June 2023. The position remained unchanged as at 31 December 2023. Tullow accounted for this as an asset acquisition at nil cost. The withdrawal of the partners and an upward revision to the Group\u2019s oil prices as detailed in note 9 are considered to be impairment assessment triggers for the asset as at 31 December 2023, and in line with its accounting policy the Group has performed a VIU assessment. The cash flows were discounted using a pre-tax nominal discount rate of 20% (2022: 20%). This resulted in an NPV significantly in excess of the book value of $260.1 million. However, the Group has identified the following uncertainties in respect of the Group\u2019s ability to realise the estimated VIU; receiving and subsequently finalising an acceptable offer from a strategic partner and securing governmental approvals relating thereto, obtaining financing for the project and government deliverables in form of provision of required infrastructure and fiscal terms. These items require satisfactory resolution before the Group can take a Final Investment Decision (FID). The Group continues to progress with the farm-down process. Due to the binary nature of these uncertainties the Group was unable to either adjust the cash flows 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. Certain risks have increased since 31 December 2022, predominantly around farm-down and project financing. This has been partially offset by an increased equity interest in the project and changes in oil price assumptions. Based on this, the NPV has been revised to $242.2 million and an impairment of $17.9 million has been recognised as at 31 December 2023. 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 $242.2 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 specified above would increase the impairment charge by $37.9 million, whilst increases to oil prices specified above would result in a credit to the impairment charge of $37.7 million. A 1% change in the pre- tax discount rate would result in an additional impairment charge of $33.9 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. For Net Zero Emissions sensitivities refer to page 45 of the TCFD. Guyana On 10 August 2023, Tullow announced that it had agreed to sell its total interest in Tullow Guyana B.V., which includes the Orinduik licence (60% operated equity) in Guyana, to Eco Guyana Oil and Gas (Barbados) Limited in exchange for an upfront cash consideration of $0.7 million and contingent consideration linked to a series of potential future milestones. The transaction completed on 16 November 2023 and resulted in $0.7 million of gain on disposal included in Other gains the income statement.
2022
Remaining
Rationale for 2022 recoverable
2022 write-off amount
Country
CGU
write-off $m $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.", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-365": { "value": "
Note 9. Property, plant and equipment
2023 2023 2023 2022 2022 2022
Oil Other Right Oil Other Right
and gas fixed of use 2023 and gas fixed of use 2022
assets assets assets Total assets assets assets Total
Notes $m $m $m $m $m $m $m $m
Cost
At 1 January
11,182.6
30.0
1,196.8
12,409.4
10,521.7
69.5
1,091.7
11,682.9
Additions
1
416.1
2.3
81.1
499.5
305.2
2.0
63.5
370.7
Acquisitions
\u2013
\u2013
\u2013
\u2013
473.2
\u2013
\u2013
473.2
Transfer
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
86.6
86.6
Transfer to assets
held for sale
14
(302.8)
\u2013
\u2013
(302.8)
\u2013
\u2013
\u2013
\u2013
Asset retirement
(67.7)
(11.0)
(10.6)
(89.3)
\u2013
(38.1)
(41.7)
(79.8)
Currency translation
adjustments
53.9
0.6
1.5
56.0
(117.5)
(3.4)
(3.3)
(124.2)
At 31 December
11,282.1
21.9
1,268.8
12,572.8
11,182.6
30.0
1,196.8
12,409.4
Depreciation, depletion,
amortisation and impairment
At 1 January
(8,888.4)
(24.4)
(515.2)
(9,428.0)
(8,263.7)
(53.8)
(450.8)
(8,768.3)
Charge for the year
4
(351.6)
(3.6)
(81.4)
(436.6)
(353.7)
(11.2)
(60.9)
(425.8)
Impairment loss
(399.1)
\u2013
(9.0)
(408.1)
(391.2)
\u2013
\u2013
(391.2)
Capitalised depreciation
\u2013
\u2013
(49.3)
(49.3)
\u2013
\u2013
(46.1)
(46.1)
Transfer to assets
held for sale
14
247.6
\u2013
\u2013
247.6
\u2013
\u2013
\u2013
\u2013
Asset retirement
67.7
11.0
10.6
89.3
\u2013
38.1
41.7
79.8
Currency translation
adjustments
(53.9)
(0.5)
(0.5)
(54.9)
120.2
2.5
0.9
123.6
At 31 December
(9,377.7)
(17.5)
(644.8)
(10,040.0)
(8,888.4)
(24.4)
(515.2)
(9,428.0)
Net book value at 31 December
1,904.4
4.4
624.0
2,532.8
2,294.2
5.6
681.6
2,981.4
1
1
1. This relates to an acquisition through business combination discussed in note 15 of the 2022 Annual Report and Accounts.
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.
During 2023 and 2022 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
2023
$78/bbl
$75/bbl
$75/bbl
$75/bbl
$75/bbl
$75/bbl inflated at 2%
2022
$84/bbl
$79/bbl
$70/bbl
$70/bbl
$70/bbl
$70/bbl inflated at 2%
2023
Remaining
Trigger for 2023 Pre-tax recoverable
2023 Impairment discount rate
amount
g
impairment $m assumption $m
Espoir (C\u00f4te d\u2019Ivoire)
a, c
53.5
14%
0.4
TEN (Ghana)
b, c
301.2
14%
528.3
Mauritania
d
27.9
n/a
\u2013
UK CGU
d, e
16.5
n/a
\u2013
UK Corporate
f
9.0
n/a
\u2013
Impairment
408.1
a. Increase in production and development costs.
b. Revision of value based on revisions to reserves.
c. Revision of short, medium and long-term oil price assumptions.
d. Change to decommissioning estimate.
e. The fields in the UK are grouped into one CGU as all fields within those countries share critical gas infrastructure.
f. Fully impaired right-of-use asset relating to a vacant office space.
g. The remaining recoverable amount of the asset is its value in use.
Impairments identified in the TEN fields of $301.2 million were primarily due to lower 2P reserves partially offset by an
increase in oil price. This was primarily due to delays in gaining approval for the amended TEN PoD which has led to the
deferral of investment and continued field decline.
Oil prices stated above are benchmark prices to which an individual field price differential is applied. All impairment
assessments are prepared on a VIU basis using discounted future cash flows based on 2P reserves profiles. 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 specified above would increase the impairment charge by $76.4 million for Ghana and
increase the impairment by $0.4 million for Non-Operated, whilst increases to oil prices specified above would result in
a reduction in the impairment charge of $72.6 million for Ghana and $17.1 million for Non-Operated. A 1% increase in the
pre-tax discount rate would increase the impairment by $15.6 million for Ghana and increase the impairment by $0.4
million for Non-Operated. The Group believes a 1% increase 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 page 45 of the TCFD and note 25. Climate change and energy transition.
2022
Trigger for 2022 Remaining
2022 Impairment/ Pre-tax recoverable
impairment/ (reversal) discount rate
amount
d
(reversal) $m assumption $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 fields in the UK are grouped into one CGU as all fields within those countries share critical gas infrastructure.
d. The remaining recoverable amount of the asset is its value in use.
Impairments identified in the TEN fields 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 field price differential is applied. All impairment
assessments are prepared on a VIU basis using discounted future cash flows based on 2P reserves profiles. 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 specified 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 specified 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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-366": { "value": "
Note 10. Other assets
2023 2022
$m $m
Non-current
Amounts due from Joint Venture Partners
332.5
323.3
VAT recoverable
6.1
3.8
338.6
327.1
Current
Amounts due from Joint Venture Partners
498.1
452.3
Underlifts
47.8
76.2
Prepayments
21.1
31.3
Other current assets
4.2
8.1
571.2
567.9
909.8
895.0
The increase in current receivables from JV Partners compared to December 2022 mainly relates to partner\u2019s share of
increased accrual balances (note 15), net increase in GNPC (Ghana National Petroleum Corporation) receivable and other
working capital movements, partially offset by a lower balance of current receivables relating to leases (note 18).
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-455": { "value": "Note 10. Other assets
2023 2022
$m $m
Non-current
Amounts due from Joint Venture Partners
332.5
323.3
VAT recoverable
6.1
3.8
338.6
327.1
Current
Amounts due from Joint Venture Partners
498.1
452.3
Underlifts
47.8
76.2
Prepayments
21.1
31.3
Other current assets
4.2
8.1
571.2
567.9
909.8
895.0
The increase in current receivables from JV Partners compared to December 2022 mainly relates to partner\u2019s share of increased accrual balances (note 15), net increase in GNPC (Ghana National Petroleum Corporation) receivable and other working capital movements, partially offset by a lower balance of current receivables relating to leases (note 18). Note 12. Trade receivables Trade receivables comprise amounts due for the sale of oil and gas. They are generally due for settlement within 30\u201360 days and are therefore all classified as current. The Group holds the trade receivables with the objective of collecting the contractual cash flows and therefore measures them subsequently at amortised cost using the effective interest method. The balance of trade receivables as at 31 December 2023 of $43.5 million (2022: $26.8 million) mainly relates to gas sales in Ghana. Note 20. Deferred taxation
Accelerated Other Deferred
tax Decommiss- Tax temporary petroleum
depreciation ioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
(143.6)
\u2013
\u2013
\u2013
\u2013
\u2013
(143.6)
Exchange differences
(0.2)
\u2013
\u2013
\u2013
\u2013
(1.8)
(2.0)
At 1 January 2023
(558.1)
65.9
35.8
(99.0)
15.8
2.6
(537.0)
Credit/(charge) to income statement
117.9
1.7
(28.4)
40.9
\u2013
3.8
135.9
Exchange differences
\u2013
\u2013
\u2013
\u2013
\u2013
0.2
0.2
At 31 December 2023
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
1
2023 2022
$m $m
Deferred tax liabilities
(420.5)
(551.5)
Deferred tax assets
19.6
14.5
(400.9)
(537.0)
1. This relates to an acquisition through business combination discussed in note 15 of the 2022 Annual Report and Accounts. The majority of the Group\u2019s 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 profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability 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:DisclosureOfOtherAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-436": { "value": "Note 10. Other assets
2023 2022
$m $m
Non-current
Amounts due from Joint Venture Partners
332.5
323.3
VAT recoverable
6.1
3.8
338.6
327.1
Current
Amounts due from Joint Venture Partners
498.1
452.3
Underlifts
47.8
76.2
Prepayments
21.1
31.3
Other current assets
4.2
8.1
571.2
567.9
909.8
895.0
The increase in current receivables from JV Partners compared to December 2022 mainly relates to partner\u2019s share of increased accrual balances (note 15), net increase in GNPC (Ghana National Petroleum Corporation) receivable and other working capital movements, partially offset by a lower balance of current receivables relating to leases (note 18). ", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-408": { "value": "Note 10. Other assets
2023 2022
$m $m
Non-current
Amounts due from Joint Venture Partners
332.5
323.3
VAT recoverable
6.1
3.8
338.6
327.1
Current
Amounts due from Joint Venture Partners
498.1
452.3
Underlifts
47.8
76.2
Prepayments
21.1
31.3
Other current assets
4.2
8.1
571.2
567.9
909.8
895.0
The increase in current receivables from JV Partners compared to December 2022 mainly relates to partner\u2019s share of increased accrual balances (note 15), net increase in GNPC (Ghana National Petroleum Corporation) receivable and other working capital movements, partially offset by a lower balance of current receivables relating to leases (note 18). ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-367": { "value": "
Note 11. Inventories
2023 2022
$m $m
Warehouse stock and materials
71.5
69.1
Oil stock
35.8
112.5
107.3
181.6
The decrease in oil stock from 31 December 2022 is driven by a decrease in Gabon of $70.6 million due to an additional
lifting in November 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-368": { "value": "
Note 12. Trade receivables
Trade receivables comprise amounts due for the sale of oil and gas. They are generally due for settlement within 30\u201360
days and are therefore all classified as current. The Group holds the trade receivables with the objective of collecting the
contractual cash flows and therefore measures them subsequently at amortised cost using the effective interest method.
The balance of trade receivables as at 31 December 2023 of $43.5 million (2022: $26.8 million) mainly relates to gas sales
in Ghana.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-369": { "value": "
Note 13. Cash and cash equivalents
2023 2022
$m $m
Cash at bank
114.9
305.3
Short-term deposits and other cash equivalents
384.1
331.0
499.0
636.3
Cash and cash equivalents includes an amount of $36.9 million (2022: $74.7 million) which the Group holds as operator
in Joint Venture bank accounts. Included within cash at bank is $4.5 million (2022: $7.0 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-370": { "value": "
Note 14. Assets and liabilities classified as held for sale
On 28 April 2023, Tullow announced that through its wholly owned subsidiary, Tullow Oil Gabon S.A., it had signed an
Asset Swap Agreement (ASA) with Perenco Oil and Gas Gabon S.A. (Perenco). Under the ASA, Tullow has agreed to
assign and transfer certain of its existing participating interests in Limande, Turnix, M\u2019oba, Oba and 17.5% in Simba assets
to Perenco in return for the assignment and transfer by Perenco of 15% if its participating interests in Kowe (Tchatamba)
and 20% of its participating interests in DE8 licence to Tullow.
Due to the agreed neutrality of the transaction, no additional consideration is payable by either party in respect thereof.
The ASA includes provisions to ensure the neutrality of the transaction via cash adjustments for the period between
economic date and completion date.
On completion, all assets and associated liabilities relating to the existing participating interests held in Limande, Turnix,
M\u2019Oba and Oba assets, together with 17.5% of Tullow\u2019s interest in Simba, will be disposed. All assets impacted by the
transaction are included in the \u2018Non-Operated\u2019 Business Unit applied for segment performance reporting.
Management concluded that the asset met the IFRS 5 Held for Sale criteria on 19 July 2023, when the agreed form of the
amendment to the Tullow Protocol was submitted to the relevant Governmental Authority of the Gabonese Republic (the
Tullow Protocol is an investment convention that applies to certain Tullow licences). All other conditions precedent to the
completion of the transaction were considered reasonably certain to occur within 12 months of 19 July.
The transaction completed on 29 February 2024. Refer to note 26. Events since 31 December 2023.
The major classes of assets and liabilities comprising the assets classified as held for sale as at 31 December 2023 were
as follows:
2023
$m
Assets
Property, plant and equipment
55.2
Other debtors
0.6
Assets classified as held for sale
55.8
Liabilities
Other payables
(1.4)
Accruals
(2.0)
Decommissioning provision
(14.2)
Liabilities directly associated with assets classified as held for sale
(17.6)
Net assets directly associated with disposal group
38.2
", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsHeldForSaleAndDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-409": { "value": "Note 14. Assets and liabilities classified as held for sale On 28 April 2023, Tullow announced that through its wholly owned subsidiary, Tullow Oil Gabon S.A., it had signed an Asset Swap Agreement (ASA) with Perenco Oil and Gas Gabon S.A. (Perenco). Under the ASA, Tullow has agreed to assign and transfer certain of its existing participating interests in Limande, Turnix, M\u2019oba, Oba and 17.5% in Simba assets to Perenco in return for the assignment and transfer by Perenco of 15% if its participating interests in Kowe (Tchatamba) and 20% of its participating interests in DE8 licence to Tullow. Due to the agreed neutrality of the transaction, no additional consideration is payable by either party in respect thereof. The ASA includes provisions to ensure the neutrality of the transaction via cash adjustments for the period between economic date and completion date. On completion, all assets and associated liabilities relating to the existing participating interests held in Limande, Turnix, M\u2019Oba and Oba assets, together with 17.5% of Tullow\u2019s interest in Simba, will be disposed. All assets impacted by the transaction are included in the \u2018Non-Operated\u2019 Business Unit applied for segment performance reporting. Management concluded that the asset met the IFRS 5 Held for Sale criteria on 19 July 2023, when the agreed form of the amendment to the Tullow Protocol was submitted to the relevant Governmental Authority of the Gabonese Republic (the Tullow Protocol is an investment convention that applies to certain Tullow licences). All other conditions precedent to the completion of the transaction were considered reasonably certain to occur within 12 months of 19 July. The transaction completed on 29 February 2024. Refer to note 26. Events since 31 December 2023. The major classes of assets and liabilities comprising the assets classified as held for sale as at 31 December 2023 were as follows:
2023
$m
Assets
Property, plant and equipment
55.2
Other debtors
0.6
Assets classified as held for sale
55.8
Liabilities
Other payables
(1.4)
Accruals
(2.0)
Decommissioning provision
(14.2)
Liabilities directly associated with assets classified as held for sale
(17.6)
Net assets directly associated with disposal group
38.2
", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-411": { "value": "
Note 15. Trade and other payables
Current liabilities
2023 2022
Notes $m $m
Trade payables
22.3
68.4
Other payables
65.3
51.4
Overlifts
3.1
\u2013
Accruals
498.6
379.3
Current portion of lease liabilities
18
185.7
251.2
775.0
750.2
Accruals mainly relate to capital expenditure, interest expense on bonds and staff-related expenses. The movement in the
balance is predominantly driven by an increased level of activity in Ghana during the year relating to Jubilee South East.
Trade and other payables are non-interest bearing except for leases (note 18). The change in trade payables and in other
payables represents timing differences and levels of work activity.
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 10).
The movement in current lease liabilities is mainly driven by the remeasurement of the TEN FPSO lease discussed in note 18.
Non-current liabilities
2023 2022
Notes $m $m
Other non-current liabilities
62.2
47.1
Non-current portion of lease liabilities
18
721.0
732.9
783.2
780.0
1
1. Other non-current liabilities include balances related to JV Partners.
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-437": { "value": "Note 15. Trade and other payables Current liabilities
2023 2022
Notes $m $m
Trade payables
22.3
68.4
Other payables
65.3
51.4
Overlifts
3.1
\u2013
Accruals
498.6
379.3
Current portion of lease liabilities
18
185.7
251.2
775.0
750.2
Accruals mainly relate to capital expenditure, interest expense on bonds and staff-related expenses. The movement in the balance is predominantly driven by an increased level of activity in Ghana during the year relating to Jubilee South East. Trade and other payables are non-interest bearing except for leases (note 18). The change in trade payables and in other payables represents timing differences and levels of work activity. 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 10). The movement in current lease liabilities is mainly driven by the remeasurement of the TEN FPSO lease discussed in note 18. Non-current liabilities
2023 2022
Notes $m $m
Other non-current liabilities
62.2
47.1
Non-current portion of lease liabilities
18
721.0
732.9
783.2
780.0
1 1. Other non-current liabilities include balances related to JV Partners. ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-460": { "value": "Note 15. Trade and other payables Current liabilities
2023 2022
Notes $m $m
Trade payables
22.3
68.4
Other payables
65.3
51.4
Overlifts
3.1
\u2013
Accruals
498.6
379.3
Current portion of lease liabilities
18
185.7
251.2
775.0
750.2
Accruals mainly relate to capital expenditure, interest expense on bonds and staff-related expenses. The movement in the balance is predominantly driven by an increased level of activity in Ghana during the year relating to Jubilee South East. Trade and other payables are non-interest bearing except for leases (note 18). The change in trade payables and in other payables represents timing differences and levels of work activity. 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 10). The movement in current lease liabilities is mainly driven by the remeasurement of the TEN FPSO lease discussed in note 18. Non-current liabilities
2023 2022
Notes $m $m
Other non-current liabilities
62.2
47.1
Non-current portion of lease liabilities
18
721.0
732.9
783.2
780.0
1 1. Other non-current liabilities include balances related to JV Partners. Note 20. Deferred taxation
Accelerated Other Deferred
tax Decommiss- Tax temporary petroleum
depreciation ioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
(143.6)
\u2013
\u2013
\u2013
\u2013
\u2013
(143.6)
Exchange differences
(0.2)
\u2013
\u2013
\u2013
\u2013
(1.8)
(2.0)
At 1 January 2023
(558.1)
65.9
35.8
(99.0)
15.8
2.6
(537.0)
Credit/(charge) to income statement
117.9
1.7
(28.4)
40.9
\u2013
3.8
135.9
Exchange differences
\u2013
\u2013
\u2013
\u2013
\u2013
0.2
0.2
At 31 December 2023
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
1
2023 2022
$m $m
Deferred tax liabilities
(420.5)
(551.5)
Deferred tax assets
19.6
14.5
(400.9)
(537.0)
1. This relates to an acquisition through business combination discussed in note 15 of the 2022 Annual Report and Accounts. The majority of the Group\u2019s 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 profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability 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:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-448": { "value": "Note 15. Trade and other payables Current liabilities
2023 2022
Notes $m $m
Trade payables
22.3
68.4
Other payables
65.3
51.4
Overlifts
3.1
\u2013
Accruals
498.6
379.3
Current portion of lease liabilities
18
185.7
251.2
775.0
750.2
Accruals mainly relate to capital expenditure, interest expense on bonds and staff-related expenses. The movement in the balance is predominantly driven by an increased level of activity in Ghana during the year relating to Jubilee South East. Trade and other payables are non-interest bearing except for leases (note 18). The change in trade payables and in other payables represents timing differences and levels of work activity. 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 10). The movement in current lease liabilities is mainly driven by the remeasurement of the TEN FPSO lease discussed in note 18. Non-current liabilities
2023 2022
Notes $m $m
Other non-current liabilities
62.2
47.1
Non-current portion of lease liabilities
18
721.0
732.9
783.2
780.0
1 1. Other non-current liabilities include balances related to JV Partners. ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-372": { "value": "Note 15. Trade and other payables Current liabilities
2023 2022
Notes $m $m
Trade payables
22.3
68.4
Other payables
65.3
51.4
Overlifts
3.1
\u2013
Accruals
498.6
379.3
Current portion of lease liabilities
18
185.7
251.2
775.0
750.2
Accruals mainly relate to capital expenditure, interest expense on bonds and staff-related expenses. The movement in the balance is predominantly driven by an increased level of activity in Ghana during the year relating to Jubilee South East. Trade and other payables are non-interest bearing except for leases (note 18). The change in trade payables and in other payables represents timing differences and levels of work activity. 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 10). The movement in current lease liabilities is mainly driven by the remeasurement of the TEN FPSO lease discussed in note 18. Non-current liabilities
2023 2022
Notes $m $m
Other non-current liabilities
62.2
47.1
Non-current portion of lease liabilities
18
721.0
732.9
783.2
780.0
1 1. Other non-current liabilities include balances related to JV Partners. ", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-371": { "value": "
Note 16. Borrowings
2023 2022
$m $m
Current
Borrowings \u2013 within one year
10.25% Senior Secured Notes due 2026
100.0
100.0
100.0
100.0
2023 2022
$m $m
Non-current
Borrowings \u2013 after one year but within five years
7.00% Senior Notes due 2025
489.0
792.8
10.25% Senior Secured Notes due 2026
1,371.0
1,580.0
Secured Notes Facility due 2028
124.6
\u2013
1,984.6
2,372.8
Carrying value of total borrowings
2,084.6
2,472.8
The Group\u2019s capital structure includes $1,485 million Senior Secured Notes (2026 Notes), $493 million Senior Notes (2025
Notes), $400 million Secured Notes Facility and a $500 million undrawn 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 15 May 2023, the Group made a mandatory prepayment of $100 million of the 2026 Notes.
On 20 June 2023, the Group repurchased $167 million nominal value of 2025 Notes for $100 million cash consideration
through an Unmodified Dutch Auction. A gain on early bond buyback of $65 million is recognised as other income in the
income statement.
On 13 November 2023, Tullow announced that it had entered into a $400 million secured notes facility agreement
maturing in November 2028 (Secured Notes Facility) with Glencore Energy UK Limited (Glencore). The Secured Notes
Facility is available for 18 months and proceeds are available for liability management of the 2025 Notes. The interest on
the Secured Notes Facility will be Term Secured Overnight Financing Rate (SOFR) plus 10% on drawn amounts.
On 1 December 2023, the Group repurchased $115 million nominal value of 2026 Notes for $103 million cash
consideration through an Unmodified Dutch Auction. A gain on early bond buyback of $11 million is recognised as other
income in the income statement.
On 20 December, the Group repurchased $141 million nominal value of 2025 Notes for $130 million cash consideration
through a Modified Dutch Auction. The cash consideration was funded through an equivalent drawdown under the Secured
Notes Facility. A gain on early bond buyback of $10 million is recognised as other income in the income statement.
The Group\u2019s total drawn debt reduced to $2.1 billion, consisting of $493 million nominal value 2025 Notes, $1,485 million
nominal value 2026 Notes, and $130 million outstanding under the Secured Notes Facility.
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 2023. Letters of credit amounting
to $10 million (2022: $44 million) have been issued under the facility.
Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes, Secured Notes Facility and the SSRCF are $14.3
million (2022: $20.0 million), $3.6 million (2022: $7.0 million), $5.0 million (2022: $nil) and $2.3 million (2022: $4.8 million)
respectively.
The SSRCF, the 2026 Notes and the Secured Notes Facility are senior secured obligations of Tullow Oil Plc and are
guaranteed by certain of the subsidiaries of the Group.
Capital management
The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for
shareholders and benefits to stakeholders and to safeguard the Group\u2019s ability to continue as a going concern. The Group
is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, management 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 such other 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 financial 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.
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 definitions 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.
Tullow is permitted to incur debt to refinance the 2025 Notes on a like-for-like basis, i.e. subordinated to the 2026 Notes.
Tullow is 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 Group for the period from 1 January 2021 to the end of the most recently
completed fiscal half-year for which internal financial statements are available if, after giving pro forma effect to the
payment(s), the 2P Reserves Coverage Ratio is equal to or greater than 1.5 times.
Tullow is 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 Group for the period from 1 January 2021 to the end of the most recently completed
fiscal half-year for which internal financial statements are available and 100% of Consolidated Cash Flow per year if, after
giving pro forma effect to the payment(s), 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.
Secured Notes Facility covenants
The Secured Notes Facility does not have any financial maintenance covenants. The facility is subject to substantially the
same covenants as the 2026 Notes, with additional restrictions related to the use of proceeds from any incurrence of new
indebtedness ranking senior to the facility or sharing the same collateral.
Tullow is permitted to refinance the SSRCF and the 2026 Notes on a like-for-like basis.
Tullow is permitted to refinance the 2025 Notes with new indebtedness which is unsecured and ranks junior to the
Secured Notes Facility.
Note 17. Financial instruments
Financial risk management objectives
The Group\u2019s Corporate Treasury function provides services to the business, coordinates access to international financial
markets, monitors and manages the financial 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 financial instruments to hedge these risk
exposures, if deemed appropriate. The use of financial 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 financial instruments, including derivatives, for speculative purposes.
2023 2022
$m $m
Financial assets
Financial assets at amortised cost
Trade receivables
43.5
26.8
Amounts due from Joint Venture Partners
830.6
775.6
Cash and cash equivalents
499.0
636.3
1,373.1
1,438.7
Financial liabilities
Liabilities at amortised cost
Trade payables
84.5
115.4
Other payables
567.0
430.7
Borrowings
2,084.6
2,472.8
Lease liabilities
906.7
984.1
Derivative financial instruments
Used for hedging
35.0
244.2
3,677.8
4,247.3
Fair values of financial assets and liabilities
With the exception of the 2026 Notes and the 2025 Notes, the Group considers the carrying value of all its financial 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 2023, was $1,327.3 million (2022: $1,364.8 million) and $458.3 million (2022: $490.0
million) respectively. These are compared to their carrying value of $1,470.9 million (2022: $1,680.0 million) and $489.0
million (2022: $792.9 million). The 2026 Notes and the 2025 Notes are categorised as level 1 in the fair value hierarchy.
No material financial assets are impaired at the balance sheet date. All financial 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 flow 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:
2023 2023 2022 2022
Less than 1\u20133 2023 Less than 1\u20133 2022
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
(13.3)
\u2013
(13.3)
(162.1)
(49.7)
(211.8)
Deferred premium
Oil derivatives
(21.7)
\u2013
(21.7)
(24.2)
(8.2)
(32.4)
Total liabilities
(35.0)
\u2013
(35.0)
(186.3)
(57.9)
(244.2)
Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide.
The following provides an analysis of the Group\u2019s financial 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 (2022: Level 2). There were no transfers between fair value levels during the year.
For financial 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 significant to the fair
value measurement as a whole) at the end of each reporting period.
Offsetting of financial 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 identified.
The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the
amounts recognised for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and
the amounts offset in the Group balance sheet.
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2022 $m $m $m
Derivative assets
\u2013
\u2013
\u2013
Derivative liabilities
(244.2)
\u2013
(244.2)
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 2023 and 31 December 2022, all of the Group\u2019s oil derivatives have been designated as cash flow
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 flows 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.
At 31 December 2023, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements
in the first half of 2024 with c.$57/bbl weighted average floors; for the same period, c.40% of forecast production entitlements
is capped at weighted average sold calls of c.$77/bbl. In the second half of 2024, Tullow\u2019s hedge portfolio provides downside
protection for c.45% of forecast production entitlements with c.$60/bbl weighted average floors; for the same period, c.20%
of forecast production entitlements is capped at weighted average sold calls of c.$113/bbl.
For the period from June to December 2024, Tullow\u2019s hedge portfolio also includes three-way collars (with call spreads)
with weighted average sold calls of c.$85/bbl and weighted average bought calls of c.$94/bbl, providing full access to oil
price upside beyond the bought call price on c.10% of forecast production entitlements in this period.
The following table demonstrates the timing, volumes and prices of the Group\u2019s commodity hedge portfolio at year end:
Bought put Bought
First half of 2024 hedge portfolio at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight puts
11,217
$60.05
\u2013
\u2013
Collars
24,344
$55.37
$77.47
\u2013
Three way collars (call spread)
332
$60.00
$105.60
$114.53
Total/weighted average
35,893
$56.88
$77.85
$114.53
Bought put Bought
Second half of 2024 hedge position at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight Puts
6,250
$59.96
\u2013
\u2013
Collars
12,650
$60.36
$113.45
\u2013
Three way collars (call spread)
6,500
$60.00
$84.61
$93.55
Total/weighted average
25,400
$60.17
$103.66
$93.55
The following table demonstrates the sensitivity of the Group\u2019s derivative financial instruments to reasonably possible
movements in Dated Brent oil prices:
Effect on equity
Market
movement
as at 2023 2022
31 Dec 2023 $m $m
Brent oil price
25%
(95.3)
(464.4)
Brent oil price
(25%)
24.2
\u2013
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 flow hedges. The movement in the reserve for the period is recognised in other comprehensive income.
The following table summarises the cash flow hedge reserve by intrinsic and time value, net of tax effects:
2023 2022
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
(18.9)
(150.3)
Oil derivatives \u2013 time value
(16.3)
(94.4)
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:
2023 2022
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(150.3)
(39.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Revaluation gains/(losses) arising in the year
20.1
(399.5)
131.4
(110.8)
At 31 December
(18.9)
(150.3)
2023 2022 Deferred amounts in the hedge reserve \u2013 time value $m $m At 1 January (94.4) (146.9) Reclassification adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 27.8 30.8 Revaluation gains arising in the year 50.3 21.7 78.1 52.5 At 31 December (16.3) (94.4)
2023 2022
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Deferred premium paid
27.8
30.8
Net losses from commodity derivatives in sales revenue (note 2)
139.1
319.3
Interest rate risk Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates. During the financial year 2022, the Group was not exposed to interest rate risk as it only borrowed funds at fixed interest rates. Following a drawdown of the Secured Notes Facility, amounting to $130 million (note 16), the Group\u2019s borrowings are both fixed and variable interest bearing as at 31 December 2023. The Super Senior Revolving Credit Facility is based on floating interest rates and remains undrawn as at year end. Fixed rate debt comprises 2025 Notes and 2026 Notes. The interest rate profile of the Group\u2019s financial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2023 and 2022, was as follows:
2023 2022
Cash 2023 2023 Cash 2022
and cash Fixed rate Floating rate 2023 and cash Fixed rate 2022
equivalents debt debt Total equivalents debt Total
$m $m $m $m $m $m $m
US$
492.3
(1,977.8)
(129.6)
(1,615.1)
578.1
(2,500.0)
(1,921.9)
Euro
0.6
\u2013
\u2013
0.6
0.3
\u2013
0.3
Sterling
4.1
\u2013
\u2013
4.1
16.3
\u2013
16.3
XAF
0.3
\u2013
\u2013
0.3
38.8
\u2013
38.8
Other
1.7
\u2013
\u2013
1.7
2.8
\u2013
2.8
499.0
(1,977.8)
(129.6)
(1,608.4)
636.3
(2,500.0)
(1,863.7)
Most of the Group\u2019s Cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2023 and 31 December 2022. The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in interest rates:
Effect on finance costs
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
Interest rate
100 basis points
3.6
\u2013
3.6
\u2013
Interest rate
(10) basis points
(0.9)
\u2013
(0.9)
\u2013
Credit risk
The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty
credit limits and specific transaction approvals. The Group limits its counterparty credit risk on cash and cash equivalent
balances by dealing only with financial institutions with credit ratings of at least A or equivalent.
The primary credit exposures for the Group are its receivables generated by the sale of crude oil and natural gas
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. During the financial year 2023, the Group\u2019s crude sales were predominantly made to
international oil market participants including the oil majors and trading houses. In November 2023, the Group entered
into oil marketing and offtake contracts with Glencore for the Group\u2019s crude oil entitlements from the Jubilee and Ten
fields in Ghana and the Rabi Light entitlements in Gabon. JV Partners are predominantly international major oil and gas
market participants. Counterparty evaluations are conducted utilising international credit rating agency and financial
assessments. Where considered appropriate, security in the form of trade finance instruments from financial 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 significant credit risk exposure to any single counterparty or any group of counterparties. The maximum
financial exposure due to credit risk on the Group\u2019s financial assets, representing the sum of cash and cash equivalents,
investments, derivative assets, trade receivables, and receivables from Joint Venture Partners, as at 31 December 2023
was $1,373.1 million (2022: $1,438.7 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 financial derivatives. There were no foreign currency financial derivatives in
place as at 31 December 2023 (2022: 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 2023, the only material monetary assets or liabilities of the Group that were not denominated in the
functional currency of the respective subsidiaries involved were $6.7 million in non-US dollar-denominated cash and cash
equivalents (2022: $58.1 million).
The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements
in US dollar exchange rates:
Effect on profit before tax
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.1
9.7
1.1
9.7
US$/foreign currency exchange rates
(20%)
(1.7)
(14.5)
(1.7)
(14.7)
Liquidity risk
The Group manages its liquidity risk using both short-term and long-term cash flow projections, supplemented by debt
financing 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 $1.0 billion (2022: $1.1 billion) of total
facility headroom and free cash as at 31 December 2023.
The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative financial liabilities with
agreed repayment periods. The tables have been drawn up based on the undiscounted cash flows of financial liabilities
based on the earliest date on which the Group can be required to pay.
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $m
31 December 2023
Non-interest bearing
n/a
49.5
\u2013
38.1
62.2
\u2013
149.8
Lease liabilities
16.4%
45.3
55.8
203.7
734.2
337.5
1,376.5
Fixed interest rate instruments
9.9%
Principal repayments
\u2013
\u2013
100.0
1,878.0
\u2013
1,978.0
Interest charge
\u2013
17.0
164.0
220.0
\u2013
401.0
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
\u2013
5.0
15.0
69.0
\u2013
89.0
Total
94.8
77.8
520.8
3,093.4
337.5
4,124.3
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $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
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-410": { "value": "Note 16. Borrowings
2023 2022
$m $m
Current
Borrowings \u2013 within one year
10.25% Senior Secured Notes due 2026
100.0
100.0
100.0
100.0
2023 2022
$m $m
Non-current
Borrowings \u2013 after one year but within five years
7.00% Senior Notes due 2025
489.0
792.8
10.25% Senior Secured Notes due 2026
1,371.0
1,580.0
Secured Notes Facility due 2028
124.6
\u2013
1,984.6
2,372.8
Carrying value of total borrowings
2,084.6
2,472.8
The Group\u2019s capital structure includes $1,485 million Senior Secured Notes (2026 Notes), $493 million Senior Notes (2025 Notes), $400 million Secured Notes Facility and a $500 million undrawn 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 15 May 2023, the Group made a mandatory prepayment of $100 million of the 2026 Notes. On 20 June 2023, the Group repurchased $167 million nominal value of 2025 Notes for $100 million cash consideration through an Unmodified Dutch Auction. A gain on early bond buyback of $65 million is recognised as other income in the income statement. On 13 November 2023, Tullow announced that it had entered into a $400 million secured notes facility agreement maturing in November 2028 (Secured Notes Facility) with Glencore Energy UK Limited (Glencore). The Secured Notes Facility is available for 18 months and proceeds are available for liability management of the 2025 Notes. The interest on the Secured Notes Facility will be Term Secured Overnight Financing Rate (SOFR) plus 10% on drawn amounts. On 1 December 2023, the Group repurchased $115 million nominal value of 2026 Notes for $103 million cash consideration through an Unmodified Dutch Auction. A gain on early bond buyback of $11 million is recognised as other income in the income statement. On 20 December, the Group repurchased $141 million nominal value of 2025 Notes for $130 million cash consideration through a Modified Dutch Auction. The cash consideration was funded through an equivalent drawdown under the Secured Notes Facility. A gain on early bond buyback of $10 million is recognised as other income in the income statement. The Group\u2019s total drawn debt reduced to $2.1 billion, consisting of $493 million nominal value 2025 Notes, $1,485 million nominal value 2026 Notes, and $130 million outstanding under the Secured Notes Facility. 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 2023. Letters of credit amounting to $10 million (2022: $44 million) have been issued under the facility. Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes, Secured Notes Facility and the SSRCF are $14.3 million (2022: $20.0 million), $3.6 million (2022: $7.0 million), $5.0 million (2022: $nil) and $2.3 million (2022: $4.8 million) respectively. The SSRCF, the 2026 Notes and the Secured Notes Facility are senior secured obligations of Tullow Oil Plc and are guaranteed by certain of the subsidiaries of the Group. Capital management The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Group\u2019s ability to continue as a going concern. The Group is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, management 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 such other 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 financial 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. 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 definitions 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. Tullow is permitted to incur debt to refinance the 2025 Notes on a like-for-like basis, i.e. subordinated to the 2026 Notes. Tullow is 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 Group for the period from 1 January 2021 to the end of the most recently completed fiscal half-year for which internal financial statements are available if, after giving pro forma effect to the payment(s), the 2P Reserves Coverage Ratio is equal to or greater than 1.5 times. Tullow is 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 Group for the period from 1 January 2021 to the end of the most recently completed fiscal half-year for which internal financial statements are available and 100% of Consolidated Cash Flow per year if, after giving pro forma effect to the payment(s), 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. Secured Notes Facility covenants The Secured Notes Facility does not have any financial maintenance covenants. The facility is subject to substantially the same covenants as the 2026 Notes, with additional restrictions related to the use of proceeds from any incurrence of new indebtedness ranking senior to the facility or sharing the same collateral. Tullow is permitted to refinance the SSRCF and the 2026 Notes on a like-for-like basis. Tullow is permitted to refinance the 2025 Notes with new indebtedness which is unsecured and ranks junior to the Secured Notes Facility. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-461": { "value": "Note 17. Financial instruments Financial risk management objectives The Group\u2019s Corporate Treasury function provides services to the business, coordinates access to international financial markets, monitors and manages the financial 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 financial instruments to hedge these risk exposures, if deemed appropriate. The use of financial 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 financial instruments, including derivatives, for speculative purposes.
2023 2022
$m $m
Financial assets
Financial assets at amortised cost
Trade receivables
43.5
26.8
Amounts due from Joint Venture Partners
830.6
775.6
Cash and cash equivalents
499.0
636.3
1,373.1
1,438.7
Financial liabilities
Liabilities at amortised cost
Trade payables
84.5
115.4
Other payables
567.0
430.7
Borrowings
2,084.6
2,472.8
Lease liabilities
906.7
984.1
Derivative financial instruments
Used for hedging
35.0
244.2
3,677.8
4,247.3
Fair values of financial assets and liabilities With the exception of the 2026 Notes and the 2025 Notes, the Group considers the carrying value of all its financial 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 2023, was $1,327.3 million (2022: $1,364.8 million) and $458.3 million (2022: $490.0 million) respectively. These are compared to their carrying value of $1,470.9 million (2022: $1,680.0 million) and $489.0 million (2022: $792.9 million). The 2026 Notes and the 2025 Notes are categorised as level 1 in the fair value hierarchy. No material financial assets are impaired at the balance sheet date. All financial 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 flow 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:
2023 2023 2022 2022
Less than 1\u20133 2023 Less than 1\u20133 2022
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
(13.3)
\u2013
(13.3)
(162.1)
(49.7)
(211.8)
Deferred premium
Oil derivatives
(21.7)
\u2013
(21.7)
(24.2)
(8.2)
(32.4)
Total liabilities
(35.0)
\u2013
(35.0)
(186.3)
(57.9)
(244.2)
Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide. The following provides an analysis of the Group\u2019s financial 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 (2022: Level 2). There were no transfers between fair value levels during the year. For financial 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 significant to the fair value measurement as a whole) at the end of each reporting period. Offsetting of financial 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 identified. The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts recognised for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the Group balance sheet.
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2022 $m $m $m
Derivative assets
\u2013
\u2013
\u2013
Derivative liabilities
(244.2)
\u2013
(244.2)
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 2023 and 31 December 2022, all of the Group\u2019s oil derivatives have been designated as cash flow 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 flows 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. At 31 December 2023, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2024 with c.$57/bbl weighted average floors; for the same period, c.40% of forecast production entitlements is capped at weighted average sold calls of c.$77/bbl. In the second half of 2024, Tullow\u2019s hedge portfolio provides downside protection for c.45% of forecast production entitlements with c.$60/bbl weighted average floors; for the same period, c.20% of forecast production entitlements is capped at weighted average sold calls of c.$113/bbl. For the period from June to December 2024, Tullow\u2019s hedge portfolio also includes three-way collars (with call spreads) with weighted average sold calls of c.$85/bbl and weighted average bought calls of c.$94/bbl, providing full access to oil price upside beyond the bought call price on c.10% of forecast production entitlements in this period. The following table demonstrates the timing, volumes and prices of the Group\u2019s commodity hedge portfolio at year end:
Bought put Bought
First half of 2024 hedge portfolio at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight puts
11,217
$60.05
\u2013
\u2013
Collars
24,344
$55.37
$77.47
\u2013
Three way collars (call spread)
332
$60.00
$105.60
$114.53
Total/weighted average
35,893
$56.88
$77.85
$114.53
Bought put Bought
Second half of 2024 hedge position at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight Puts
6,250
$59.96
\u2013
\u2013
Collars
12,650
$60.36
$113.45
\u2013
Three way collars (call spread)
6,500
$60.00
$84.61
$93.55
Total/weighted average
25,400
$60.17
$103.66
$93.55
The following table demonstrates the sensitivity of the Group\u2019s derivative financial instruments to reasonably possible movements in Dated Brent oil prices:
Effect on equity
Market
movement
as at 2023 2022
31 Dec 2023 $m $m
Brent oil price
25%
(95.3)
(464.4)
Brent oil price
(25%)
24.2
\u2013
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 flow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the cash flow hedge reserve by intrinsic and time value, net of tax effects:
2023 2022
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
(18.9)
(150.3)
Oil derivatives \u2013 time value
(16.3)
(94.4)
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:
2023 2022
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(150.3)
(39.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Revaluation gains/(losses) arising in the year
20.1
(399.5)
131.4
(110.8)
At 31 December
(18.9)
(150.3)
2023 2022 Deferred amounts in the hedge reserve \u2013 time value $m $m At 1 January (94.4) (146.9) Reclassification adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 27.8 30.8 Revaluation gains arising in the year 50.3 21.7 78.1 52.5 At 31 December (16.3) (94.4)
2023 2022
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Deferred premium paid
27.8
30.8
Net losses from commodity derivatives in sales revenue (note 2)
139.1
319.3
Interest rate risk Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates. During the financial year 2022, the Group was not exposed to interest rate risk as it only borrowed funds at fixed interest rates. Following a drawdown of the Secured Notes Facility, amounting to $130 million (note 16), the Group\u2019s borrowings are both fixed and variable interest bearing as at 31 December 2023. The Super Senior Revolving Credit Facility is based on floating interest rates and remains undrawn as at year end. Fixed rate debt comprises 2025 Notes and 2026 Notes. The interest rate profile of the Group\u2019s financial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2023 and 2022, was as follows:
2023 2022
Cash 2023 2023 Cash 2022
and cash Fixed rate Floating rate 2023 and cash Fixed rate 2022
equivalents debt debt Total equivalents debt Total
$m $m $m $m $m $m $m
US$
492.3
(1,977.8)
(129.6)
(1,615.1)
578.1
(2,500.0)
(1,921.9)
Euro
0.6
\u2013
\u2013
0.6
0.3
\u2013
0.3
Sterling
4.1
\u2013
\u2013
4.1
16.3
\u2013
16.3
XAF
0.3
\u2013
\u2013
0.3
38.8
\u2013
38.8
Other
1.7
\u2013
\u2013
1.7
2.8
\u2013
2.8
499.0
(1,977.8)
(129.6)
(1,608.4)
636.3
(2,500.0)
(1,863.7)
Most of the Group\u2019s Cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2023 and 31 December 2022. The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in interest rates:
Effect on finance costs
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
Interest rate
100 basis points
3.6
\u2013
3.6
\u2013
Interest rate
(10) basis points
(0.9)
\u2013
(0.9)
\u2013
Credit risk The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. The Group limits its counterparty credit risk on cash and cash equivalent balances by dealing only with financial institutions with credit ratings of at least A or equivalent. The primary credit exposures for the Group are its receivables generated by the sale of crude oil and natural gas 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. During the financial year 2023, the Group\u2019s crude sales were predominantly made to international oil market participants including the oil majors and trading houses. In November 2023, the Group entered into oil marketing and offtake contracts with Glencore for the Group\u2019s crude oil entitlements from the Jubilee and Ten fields in Ghana and the Rabi Light entitlements in Gabon. JV Partners are predominantly international major oil and gas market participants. Counterparty evaluations are conducted utilising international credit rating agency and financial assessments. Where considered appropriate, security in the form of trade finance instruments from financial 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 significant credit risk exposure to any single counterparty or any group of counterparties. The maximum financial exposure due to credit risk on the Group\u2019s financial assets, representing the sum of cash and cash equivalents, investments, derivative assets, trade receivables, and receivables from Joint Venture Partners, as at 31 December 2023 was $1,373.1 million (2022: $1,438.7 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 financial derivatives. There were no foreign currency financial derivatives in place as at 31 December 2023 (2022: 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 2023, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.7 million in non-US dollar-denominated cash and cash equivalents (2022: $58.1 million). The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in US dollar exchange rates:
Effect on profit before tax
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.1
9.7
1.1
9.7
US$/foreign currency exchange rates
(20%)
(1.7)
(14.5)
(1.7)
(14.7)
Liquidity risk The Group manages its liquidity risk using both short-term and long-term cash flow projections, supplemented by debt financing 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 $1.0 billion (2022: $1.1 billion) of total facility headroom and free cash as at 31 December 2023. The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative financial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Group can be required to pay.
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $m
31 December 2023
Non-interest bearing
n/a
49.5
\u2013
38.1
62.2
\u2013
149.8
Lease liabilities
16.4%
45.3
55.8
203.7
734.2
337.5
1,376.5
Fixed interest rate instruments
9.9%
Principal repayments
\u2013
\u2013
100.0
1,878.0
\u2013
1,978.0
Interest charge
\u2013
17.0
164.0
220.0
\u2013
401.0
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
\u2013
5.0
15.0
69.0
\u2013
89.0
Total
94.8
77.8
520.8
3,093.4
337.5
4,124.3
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $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
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-438": { "value": "
2023 2022
$m $m
Financial assets
Financial assets at amortised cost
Trade receivables
43.5
26.8
Amounts due from Joint Venture Partners
830.6
775.6
Cash and cash equivalents
499.0
636.3
1,373.1
1,438.7
Financial liabilities
Liabilities at amortised cost
Trade payables
84.5
115.4
Other payables
567.0
430.7
Borrowings
2,084.6
2,472.8
Lease liabilities
906.7
984.1
Derivative financial instruments
Used for hedging
35.0
244.2
3,677.8
4,247.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-449": { "value": "
2023 2022
$m $m
Financial assets
Financial assets at amortised cost
Trade receivables
43.5
26.8
Amounts due from Joint Venture Partners
830.6
775.6
Cash and cash equivalents
499.0
636.3
1,373.1
1,438.7
Financial liabilities
Liabilities at amortised cost
Trade payables
84.5
115.4
Other payables
567.0
430.7
Borrowings
2,084.6
2,472.8
Lease liabilities
906.7
984.1
Derivative financial instruments
Used for hedging
35.0
244.2
3,677.8
4,247.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-439": { "value": "Fair values of financial assets and liabilities With the exception of the 2026 Notes and the 2025 Notes, the Group considers the carrying value of all its financial 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 2023, was $1,327.3 million (2022: $1,364.8 million) and $458.3 million (2022: $490.0 million) respectively. These are compared to their carrying value of $1,470.9 million (2022: $1,680.0 million) and $489.0 million (2022: $792.9 million). The 2026 Notes and the 2025 Notes are categorised as level 1 in the fair value hierarchy. No material financial assets are impaired at the balance sheet date. All financial 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 flow 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:
2023 2023 2022 2022
Less than 1\u20133 2023 Less than 1\u20133 2022
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
(13.3)
\u2013
(13.3)
(162.1)
(49.7)
(211.8)
Deferred premium
Oil derivatives
(21.7)
\u2013
(21.7)
(24.2)
(8.2)
(32.4)
Total liabilities
(35.0)
\u2013
(35.0)
(186.3)
(57.9)
(244.2)
Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide. The following provides an analysis of the Group\u2019s financial 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 (2022: Level 2). There were no transfers between fair value levels during the year. For financial 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 significant to the fair value measurement as a whole) at the end of each reporting period. ", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-412": { "value": "Fair values of financial assets and liabilities With the exception of the 2026 Notes and the 2025 Notes, the Group considers the carrying value of all its financial 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 2023, was $1,327.3 million (2022: $1,364.8 million) and $458.3 million (2022: $490.0 million) respectively. These are compared to their carrying value of $1,470.9 million (2022: $1,680.0 million) and $489.0 million (2022: $792.9 million). The 2026 Notes and the 2025 Notes are categorised as level 1 in the fair value hierarchy. No material financial assets are impaired at the balance sheet date. All financial 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 flow 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:
2023 2023 2022 2022
Less than 1\u20133 2023 Less than 1\u20133 2022
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
(13.3)
\u2013
(13.3)
(162.1)
(49.7)
(211.8)
Deferred premium
Oil derivatives
(21.7)
\u2013
(21.7)
(24.2)
(8.2)
(32.4)
Total liabilities
(35.0)
\u2013
(35.0)
(186.3)
(57.9)
(244.2)
Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide. The following provides an analysis of the Group\u2019s financial 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 (2022: Level 2). There were no transfers between fair value levels during the year. For financial 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 significant to the fair value measurement as a whole) at the end of each reporting period. ", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-456": { "value": "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 flow 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:
2023 2023 2022 2022
Less than 1\u20133 2023 Less than 1\u20133 2022
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
(13.3)
\u2013
(13.3)
(162.1)
(49.7)
(211.8)
Deferred premium
Oil derivatives
(21.7)
\u2013
(21.7)
(24.2)
(8.2)
(32.4)
Total liabilities
(35.0)
\u2013
(35.0)
(186.3)
(57.9)
(244.2)
Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide. The following provides an analysis of the Group\u2019s financial 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 (2022: Level 2). There were no transfers between fair value levels during the year. For financial 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 significant to the fair value measurement as a whole) at the end of each reporting period. Offsetting of financial 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 identified. The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts recognised for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the Group balance sheet.
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2022 $m $m $m
Derivative assets
\u2013
\u2013
\u2013
Derivative liabilities
(244.2)
\u2013
(244.2)
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 2023 and 31 December 2022, all of the Group\u2019s oil derivatives have been designated as cash flow 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 flows 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. At 31 December 2023, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2024 with c.$57/bbl weighted average floors; for the same period, c.40% of forecast production entitlements is capped at weighted average sold calls of c.$77/bbl. In the second half of 2024, Tullow\u2019s hedge portfolio provides downside protection for c.45% of forecast production entitlements with c.$60/bbl weighted average floors; for the same period, c.20% of forecast production entitlements is capped at weighted average sold calls of c.$113/bbl. For the period from June to December 2024, Tullow\u2019s hedge portfolio also includes three-way collars (with call spreads) with weighted average sold calls of c.$85/bbl and weighted average bought calls of c.$94/bbl, providing full access to oil price upside beyond the bought call price on c.10% of forecast production entitlements in this period. The following table demonstrates the timing, volumes and prices of the Group\u2019s commodity hedge portfolio at year end:
Bought put Bought
First half of 2024 hedge portfolio at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight puts
11,217
$60.05
\u2013
\u2013
Collars
24,344
$55.37
$77.47
\u2013
Three way collars (call spread)
332
$60.00
$105.60
$114.53
Total/weighted average
35,893
$56.88
$77.85
$114.53
Bought put Bought
Second half of 2024 hedge position at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight Puts
6,250
$59.96
\u2013
\u2013
Collars
12,650
$60.36
$113.45
\u2013
Three way collars (call spread)
6,500
$60.00
$84.61
$93.55
Total/weighted average
25,400
$60.17
$103.66
$93.55
The following table demonstrates the sensitivity of the Group\u2019s derivative financial instruments to reasonably possible movements in Dated Brent oil prices:
Effect on equity
Market
movement
as at 2023 2022
31 Dec 2023 $m $m
Brent oil price
25%
(95.3)
(464.4)
Brent oil price
(25%)
24.2
\u2013
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 flow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the cash flow hedge reserve by intrinsic and time value, net of tax effects:
2023 2022
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
(18.9)
(150.3)
Oil derivatives \u2013 time value
(16.3)
(94.4)
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:
2023 2022
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(150.3)
(39.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Revaluation gains/(losses) arising in the year
20.1
(399.5)
131.4
(110.8)
At 31 December
(18.9)
(150.3)
2023 2022 Deferred amounts in the hedge reserve \u2013 time value $m $m At 1 January (94.4) (146.9) Reclassification adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 27.8 30.8 Revaluation gains arising in the year 50.3 21.7 78.1 52.5 At 31 December (16.3) (94.4)
2023 2022
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Deferred premium paid
27.8
30.8
Net losses from commodity derivatives in sales revenue (note 2)
139.1
319.3
Interest rate risk Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates. During the financial year 2022, the Group was not exposed to interest rate risk as it only borrowed funds at fixed interest rates. Following a drawdown of the Secured Notes Facility, amounting to $130 million (note 16), the Group\u2019s borrowings are both fixed and variable interest bearing as at 31 December 2023. The Super Senior Revolving Credit Facility is based on floating interest rates and remains undrawn as at year end. Fixed rate debt comprises 2025 Notes and 2026 Notes. The interest rate profile of the Group\u2019s financial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2023 and 2022, was as follows:
2023 2022
Cash 2023 2023 Cash 2022
and cash Fixed rate Floating rate 2023 and cash Fixed rate 2022
equivalents debt debt Total equivalents debt Total
$m $m $m $m $m $m $m
US$
492.3
(1,977.8)
(129.6)
(1,615.1)
578.1
(2,500.0)
(1,921.9)
Euro
0.6
\u2013
\u2013
0.6
0.3
\u2013
0.3
Sterling
4.1
\u2013
\u2013
4.1
16.3
\u2013
16.3
XAF
0.3
\u2013
\u2013
0.3
38.8
\u2013
38.8
Other
1.7
\u2013
\u2013
1.7
2.8
\u2013
2.8
499.0
(1,977.8)
(129.6)
(1,608.4)
636.3
(2,500.0)
(1,863.7)
Most of the Group\u2019s Cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2023 and 31 December 2022. The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in interest rates:
Effect on finance costs
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
Interest rate
100 basis points
3.6
\u2013
3.6
\u2013
Interest rate
(10) basis points
(0.9)
\u2013
(0.9)
\u2013
Credit risk The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. The Group limits its counterparty credit risk on cash and cash equivalent balances by dealing only with financial institutions with credit ratings of at least A or equivalent. The primary credit exposures for the Group are its receivables generated by the sale of crude oil and natural gas 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. During the financial year 2023, the Group\u2019s crude sales were predominantly made to international oil market participants including the oil majors and trading houses. In November 2023, the Group entered into oil marketing and offtake contracts with Glencore for the Group\u2019s crude oil entitlements from the Jubilee and Ten fields in Ghana and the Rabi Light entitlements in Gabon. JV Partners are predominantly international major oil and gas market participants. Counterparty evaluations are conducted utilising international credit rating agency and financial assessments. Where considered appropriate, security in the form of trade finance instruments from financial 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 significant credit risk exposure to any single counterparty or any group of counterparties. The maximum financial exposure due to credit risk on the Group\u2019s financial assets, representing the sum of cash and cash equivalents, investments, derivative assets, trade receivables, and receivables from Joint Venture Partners, as at 31 December 2023 was $1,373.1 million (2022: $1,438.7 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 financial derivatives. There were no foreign currency financial derivatives in place as at 31 December 2023 (2022: 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 2023, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.7 million in non-US dollar-denominated cash and cash equivalents (2022: $58.1 million). The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in US dollar exchange rates:
Effect on profit before tax
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.1
9.7
1.1
9.7
US$/foreign currency exchange rates
(20%)
(1.7)
(14.5)
(1.7)
(14.7)
Liquidity risk The Group manages its liquidity risk using both short-term and long-term cash flow projections, supplemented by debt financing 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 $1.0 billion (2022: $1.1 billion) of total facility headroom and free cash as at 31 December 2023. The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative financial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Group can be required to pay.
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $m
31 December 2023
Non-interest bearing
n/a
49.5
\u2013
38.1
62.2
\u2013
149.8
Lease liabilities
16.4%
45.3
55.8
203.7
734.2
337.5
1,376.5
Fixed interest rate instruments
9.9%
Principal repayments
\u2013
\u2013
100.0
1,878.0
\u2013
1,978.0
Interest charge
\u2013
17.0
164.0
220.0
\u2013
401.0
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
\u2013
5.0
15.0
69.0
\u2013
89.0
Total
94.8
77.8
520.8
3,093.4
337.5
4,124.3
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $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
", "dimensions": { "concept": "ifrs-full:DisclosureOfHedgeAccountingExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-450": { "value": "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 flow 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:
2023 2023 2022 2022
Less than 1\u20133 2023 Less than 1\u20133 2022
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
(13.3)
\u2013
(13.3)
(162.1)
(49.7)
(211.8)
Deferred premium
Oil derivatives
(21.7)
\u2013
(21.7)
(24.2)
(8.2)
(32.4)
Total liabilities
(35.0)
\u2013
(35.0)
(186.3)
(57.9)
(244.2)
Derivatives\u2019 maturity and the timing of their recycling into income or expense coincide. The following provides an analysis of the Group\u2019s financial 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 (2022: Level 2). There were no transfers between fair value levels during the year. For financial 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 significant to the fair value measurement as a whole) at the end of each reporting period. Offsetting of financial 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 identified. The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts recognised for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the Group balance sheet.
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2022 $m $m $m
Derivative assets
\u2013
\u2013
\u2013
Derivative liabilities
(244.2)
\u2013
(244.2)
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 2023 and 31 December 2022, all of the Group\u2019s oil derivatives have been designated as cash flow 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 flows 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. At 31 December 2023, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2024 with c.$57/bbl weighted average floors; for the same period, c.40% of forecast production entitlements is capped at weighted average sold calls of c.$77/bbl. In the second half of 2024, Tullow\u2019s hedge portfolio provides downside protection for c.45% of forecast production entitlements with c.$60/bbl weighted average floors; for the same period, c.20% of forecast production entitlements is capped at weighted average sold calls of c.$113/bbl. For the period from June to December 2024, Tullow\u2019s hedge portfolio also includes three-way collars (with call spreads) with weighted average sold calls of c.$85/bbl and weighted average bought calls of c.$94/bbl, providing full access to oil price upside beyond the bought call price on c.10% of forecast production entitlements in this period. The following table demonstrates the timing, volumes and prices of the Group\u2019s commodity hedge portfolio at year end:
Bought put Bought
First half of 2024 hedge portfolio at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight puts
11,217
$60.05
\u2013
\u2013
Collars
24,344
$55.37
$77.47
\u2013
Three way collars (call spread)
332
$60.00
$105.60
$114.53
Total/weighted average
35,893
$56.88
$77.85
$114.53
Bought put Bought
Second half of 2024 hedge position at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight Puts
6,250
$59.96
\u2013
\u2013
Collars
12,650
$60.36
$113.45
\u2013
Three way collars (call spread)
6,500
$60.00
$84.61
$93.55
Total/weighted average
25,400
$60.17
$103.66
$93.55
The following table demonstrates the sensitivity of the Group\u2019s derivative financial instruments to reasonably possible movements in Dated Brent oil prices:
Effect on equity
Market
movement
as at 2023 2022
31 Dec 2023 $m $m
Brent oil price
25%
(95.3)
(464.4)
Brent oil price
(25%)
24.2
\u2013
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 flow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the cash flow hedge reserve by intrinsic and time value, net of tax effects:
2023 2022
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
(18.9)
(150.3)
Oil derivatives \u2013 time value
(16.3)
(94.4)
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:
2023 2022
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(150.3)
(39.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Revaluation gains/(losses) arising in the year
20.1
(399.5)
131.4
(110.8)
At 31 December
(18.9)
(150.3)
2023 2022 Deferred amounts in the hedge reserve \u2013 time value $m $m At 1 January (94.4) (146.9) Reclassification adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 27.8 30.8 Revaluation gains arising in the year 50.3 21.7 78.1 52.5 At 31 December (16.3) (94.4)
2023 2022
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Deferred premium paid
27.8
30.8
Net losses from commodity derivatives in sales revenue (note 2)
139.1
319.3
Interest rate risk Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates. During the financial year 2022, the Group was not exposed to interest rate risk as it only borrowed funds at fixed interest rates. Following a drawdown of the Secured Notes Facility, amounting to $130 million (note 16), the Group\u2019s borrowings are both fixed and variable interest bearing as at 31 December 2023. The Super Senior Revolving Credit Facility is based on floating interest rates and remains undrawn as at year end. Fixed rate debt comprises 2025 Notes and 2026 Notes. The interest rate profile of the Group\u2019s financial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2023 and 2022, was as follows:
2023 2022
Cash 2023 2023 Cash 2022
and cash Fixed rate Floating rate 2023 and cash Fixed rate 2022
equivalents debt debt Total equivalents debt Total
$m $m $m $m $m $m $m
US$
492.3
(1,977.8)
(129.6)
(1,615.1)
578.1
(2,500.0)
(1,921.9)
Euro
0.6
\u2013
\u2013
0.6
0.3
\u2013
0.3
Sterling
4.1
\u2013
\u2013
4.1
16.3
\u2013
16.3
XAF
0.3
\u2013
\u2013
0.3
38.8
\u2013
38.8
Other
1.7
\u2013
\u2013
1.7
2.8
\u2013
2.8
499.0
(1,977.8)
(129.6)
(1,608.4)
636.3
(2,500.0)
(1,863.7)
Most of the Group\u2019s Cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2023 and 31 December 2022. The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in interest rates:
Effect on finance costs
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
Interest rate
100 basis points
3.6
\u2013
3.6
\u2013
Interest rate
(10) basis points
(0.9)
\u2013
(0.9)
\u2013
Credit risk The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. The Group limits its counterparty credit risk on cash and cash equivalent balances by dealing only with financial institutions with credit ratings of at least A or equivalent. The primary credit exposures for the Group are its receivables generated by the sale of crude oil and natural gas 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. During the financial year 2023, the Group\u2019s crude sales were predominantly made to international oil market participants including the oil majors and trading houses. In November 2023, the Group entered into oil marketing and offtake contracts with Glencore for the Group\u2019s crude oil entitlements from the Jubilee and Ten fields in Ghana and the Rabi Light entitlements in Gabon. JV Partners are predominantly international major oil and gas market participants. Counterparty evaluations are conducted utilising international credit rating agency and financial assessments. Where considered appropriate, security in the form of trade finance instruments from financial 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 significant credit risk exposure to any single counterparty or any group of counterparties. The maximum financial exposure due to credit risk on the Group\u2019s financial assets, representing the sum of cash and cash equivalents, investments, derivative assets, trade receivables, and receivables from Joint Venture Partners, as at 31 December 2023 was $1,373.1 million (2022: $1,438.7 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 financial derivatives. There were no foreign currency financial derivatives in place as at 31 December 2023 (2022: 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 2023, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.7 million in non-US dollar-denominated cash and cash equivalents (2022: $58.1 million). The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in US dollar exchange rates:
Effect on profit before tax
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.1
9.7
1.1
9.7
US$/foreign currency exchange rates
(20%)
(1.7)
(14.5)
(1.7)
(14.7)
Liquidity risk The Group manages its liquidity risk using both short-term and long-term cash flow projections, supplemented by debt financing 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 $1.0 billion (2022: $1.1 billion) of total facility headroom and free cash as at 31 December 2023. The following tables detail the Group\u2019s remaining contractual maturities for its non-derivative financial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Group can be required to pay.
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $m
31 December 2023
Non-interest bearing
n/a
49.5
\u2013
38.1
62.2
\u2013
149.8
Lease liabilities
16.4%
45.3
55.8
203.7
734.2
337.5
1,376.5
Fixed interest rate instruments
9.9%
Principal repayments
\u2013
\u2013
100.0
1,878.0
\u2013
1,978.0
Interest charge
\u2013
17.0
164.0
220.0
\u2013
401.0
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
\u2013
5.0
15.0
69.0
\u2013
89.0
Total
94.8
77.8
520.8
3,093.4
337.5
4,124.3
Weighted
average Less than 1\u20133 3 months 1\u20135 5+
effective 1 month months to 1 year years years Total
interest rate $m $m $m $m $m $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
", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-463": { "value": "Offsetting of financial 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 identified. The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts recognised for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the Group balance sheet.
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2022 $m $m $m
Derivative assets
\u2013
\u2013
\u2013
Derivative liabilities
(244.2)
\u2013
(244.2)
", "dimensions": { "concept": "ifrs-full:DisclosureOfOffsettingOfFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-440": { "value": "Offsetting of financial 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 identified. The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts recognised for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the Group balance sheet.
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2022 $m $m $m
Derivative assets
\u2013
\u2013
\u2013
Derivative liabilities
(244.2)
\u2013
(244.2)
", "dimensions": { "concept": "ifrs-full:DisclosureOfOffsettingOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-413": { "value": "Offsetting of financial 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 identified. The Group has entered into ISDA Master Agreements with derivative counterparties. The following table shows the amounts recognised for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the Group balance sheet.
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
Gross Net
amounts amounts
offset presented
Gross in Group in Group
amounts balance balance
recognised sheet sheet
31 December 2022 $m $m $m
Derivative assets
\u2013
\u2013
\u2013
Derivative liabilities
(244.2)
\u2013
(244.2)
", "dimensions": { "concept": "ifrs-full:DisclosureOfOffsettingOfFinancialAssetsAndFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-464": { "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 2023 and 31 December 2022, all of the Group\u2019s oil derivatives have been designated as cash flow 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 flows 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. At 31 December 2023, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2024 with c.$57/bbl weighted average floors; for the same period, c.40% of forecast production entitlements is capped at weighted average sold calls of c.$77/bbl. In the second half of 2024, Tullow\u2019s hedge portfolio provides downside protection for c.45% of forecast production entitlements with c.$60/bbl weighted average floors; for the same period, c.20% of forecast production entitlements is capped at weighted average sold calls of c.$113/bbl. For the period from June to December 2024, Tullow\u2019s hedge portfolio also includes three-way collars (with call spreads) with weighted average sold calls of c.$85/bbl and weighted average bought calls of c.$94/bbl, providing full access to oil price upside beyond the bought call price on c.10% of forecast production entitlements in this period. The following table demonstrates the timing, volumes and prices of the Group\u2019s commodity hedge portfolio at year end:
Bought put Bought
First half of 2024 hedge portfolio at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight puts
11,217
$60.05
\u2013
\u2013
Collars
24,344
$55.37
$77.47
\u2013
Three way collars (call spread)
332
$60.00
$105.60
$114.53
Total/weighted average
35,893
$56.88
$77.85
$114.53
Bought put Bought
Second half of 2024 hedge position at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight Puts
6,250
$59.96
\u2013
\u2013
Collars
12,650
$60.36
$113.45
\u2013
Three way collars (call spread)
6,500
$60.00
$84.61
$93.55
Total/weighted average
25,400
$60.17
$103.66
$93.55
The following table demonstrates the sensitivity of the Group\u2019s derivative financial instruments to reasonably possible movements in Dated Brent oil prices:
Effect on equity
Market
movement
as at 2023 2022
31 Dec 2023 $m $m
Brent oil price
25%
(95.3)
(464.4)
Brent oil price
(25%)
24.2
\u2013
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 flow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the cash flow hedge reserve by intrinsic and time value, net of tax effects:
2023 2022
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
(18.9)
(150.3)
Oil derivatives \u2013 time value
(16.3)
(94.4)
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:
2023 2022
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(150.3)
(39.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Revaluation gains/(losses) arising in the year
20.1
(399.5)
131.4
(110.8)
At 31 December
(18.9)
(150.3)
2023 2022 Deferred amounts in the hedge reserve \u2013 time value $m $m At 1 January (94.4) (146.9) Reclassification adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 27.8 30.8 Revaluation gains arising in the year 50.3 21.7 78.1 52.5 At 31 December (16.3) (94.4)
2023 2022
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Deferred premium paid
27.8
30.8
Net losses from commodity derivatives in sales revenue (note 2)
139.1
319.3
Interest rate risk Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates. During the financial year 2022, the Group was not exposed to interest rate risk as it only borrowed funds at fixed interest rates. Following a drawdown of the Secured Notes Facility, amounting to $130 million (note 16), the Group\u2019s borrowings are both fixed and variable interest bearing as at 31 December 2023. The Super Senior Revolving Credit Facility is based on floating interest rates and remains undrawn as at year end. Fixed rate debt comprises 2025 Notes and 2026 Notes. The interest rate profile of the Group\u2019s financial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2023 and 2022, was as follows:
2023 2022
Cash 2023 2023 Cash 2022
and cash Fixed rate Floating rate 2023 and cash Fixed rate 2022
equivalents debt debt Total equivalents debt Total
$m $m $m $m $m $m $m
US$
492.3
(1,977.8)
(129.6)
(1,615.1)
578.1
(2,500.0)
(1,921.9)
Euro
0.6
\u2013
\u2013
0.6
0.3
\u2013
0.3
Sterling
4.1
\u2013
\u2013
4.1
16.3
\u2013
16.3
XAF
0.3
\u2013
\u2013
0.3
38.8
\u2013
38.8
Other
1.7
\u2013
\u2013
1.7
2.8
\u2013
2.8
499.0
(1,977.8)
(129.6)
(1,608.4)
636.3
(2,500.0)
(1,863.7)
Most of the Group\u2019s Cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2023 and 31 December 2022. The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in interest rates:
Effect on finance costs
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
Interest rate
100 basis points
3.6
\u2013
3.6
\u2013
Interest rate
(10) basis points
(0.9)
\u2013
(0.9)
\u2013
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 financial derivatives. There were no foreign currency financial derivatives in place as at 31 December 2023 (2022: 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 2023, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.7 million in non-US dollar-denominated cash and cash equivalents (2022: $58.1 million). The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in US dollar exchange rates:
Effect on profit before tax
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.1
9.7
1.1
9.7
US$/foreign currency exchange rates
(20%)
(1.7)
(14.5)
(1.7)
(14.7)
", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-414": { "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 2023 and 31 December 2022, all of the Group\u2019s oil derivatives have been designated as cash flow 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 flows 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. At 31 December 2023, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2024 with c.$57/bbl weighted average floors; for the same period, c.40% of forecast production entitlements is capped at weighted average sold calls of c.$77/bbl. In the second half of 2024, Tullow\u2019s hedge portfolio provides downside protection for c.45% of forecast production entitlements with c.$60/bbl weighted average floors; for the same period, c.20% of forecast production entitlements is capped at weighted average sold calls of c.$113/bbl. For the period from June to December 2024, Tullow\u2019s hedge portfolio also includes three-way collars (with call spreads) with weighted average sold calls of c.$85/bbl and weighted average bought calls of c.$94/bbl, providing full access to oil price upside beyond the bought call price on c.10% of forecast production entitlements in this period. The following table demonstrates the timing, volumes and prices of the Group\u2019s commodity hedge portfolio at year end:
Bought put Bought
First half of 2024 hedge portfolio at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight puts
11,217
$60.05
\u2013
\u2013
Collars
24,344
$55.37
$77.47
\u2013
Three way collars (call spread)
332
$60.00
$105.60
$114.53
Total/weighted average
35,893
$56.88
$77.85
$114.53
Bought put Bought
Second half of 2024 hedge position at 31 December 2023
Bopd
(\ue01floor)
Sold call
call
Hedge structure
Straight Puts
6,250
$59.96
\u2013
\u2013
Collars
12,650
$60.36
$113.45
\u2013
Three way collars (call spread)
6,500
$60.00
$84.61
$93.55
Total/weighted average
25,400
$60.17
$103.66
$93.55
The following table demonstrates the sensitivity of the Group\u2019s derivative financial instruments to reasonably possible movements in Dated Brent oil prices:
Effect on equity
Market
movement
as at 2023 2022
31 Dec 2023 $m $m
Brent oil price
25%
(95.3)
(464.4)
Brent oil price
(25%)
24.2
\u2013
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 flow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the cash flow hedge reserve by intrinsic and time value, net of tax effects:
2023 2022
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
(18.9)
(150.3)
Oil derivatives \u2013 time value
(16.3)
(94.4)
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:
2023 2022
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(150.3)
(39.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Revaluation gains/(losses) arising in the year
20.1
(399.5)
131.4
(110.8)
At 31 December
(18.9)
(150.3)
", "dimensions": { "concept": "tullowoilplc:DisclosureOfCommodityPriceRisk", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-416": { "value": "2023 2022 Deferred amounts in the hedge reserve \u2013 time value $m $m At 1 January (94.4) (146.9) Reclassification adjustments for items included in the income statement on realisation: Oil derivatives \u2013 transferred to sales revenue 27.8 30.8 Revaluation gains arising in the year 50.3 21.7 78.1 52.5 At 31 December (16.3) (94.4)
2023 2022
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
111.3
288.5
Deferred premium paid
27.8
30.8
Net losses from commodity derivatives in sales revenue (note 2)
139.1
319.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfDetailedInformationAboutHedgesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-415": { "value": "
Interest rate risk
Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of
changes in market interest rates. During the financial year 2022, the Group was not exposed to interest rate risk as it only
borrowed funds at fixed interest rates. Following a drawdown of the Secured Notes Facility, amounting to $130 million
(note 16), the Group\u2019s borrowings are both fixed and variable interest bearing as at 31 December 2023. The Super Senior
Revolving Credit Facility is based on floating interest rates and remains undrawn as at year end.
Fixed rate debt comprises 2025 Notes and 2026 Notes.
The interest rate profile of the Group\u2019s financial assets and liabilities, excluding trade and other receivables and trade and
other payables, at 31 December 2023 and 2022, was as follows:
2023 2022
Cash 2023 2023 Cash 2022
and cash Fixed rate Floating rate 2023 and cash Fixed rate 2022
equivalents debt debt Total equivalents debt Total
$m $m $m $m $m $m $m
US$
492.3
(1,977.8)
(129.6)
(1,615.1)
578.1
(2,500.0)
(1,921.9)
Euro
0.6
\u2013
\u2013
0.6
0.3
\u2013
0.3
Sterling
4.1
\u2013
\u2013
4.1
16.3
\u2013
16.3
XAF
0.3
\u2013
\u2013
0.3
38.8
\u2013
38.8
Other
1.7
\u2013
\u2013
1.7
2.8
\u2013
2.8
499.0
(1,977.8)
(129.6)
(1,608.4)
636.3
(2,500.0)
(1,863.7)
Most of the Group\u2019s Cash and cash equivalents consisted of balances earning variable interest rates as at 31 December
2023 and 31 December 2022.
The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements
in interest rates:
Effect on finance costs
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
Interest rate
100 basis points
3.6
\u2013
3.6
\u2013
Interest rate
(10) basis points
(0.9)
\u2013
(0.9)
\u2013
", "dimensions": { "concept": "tullowoilplc:DisclosureOfInterestRateRisk", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-417": { "value": "Credit risk The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. The Group limits its counterparty credit risk on cash and cash equivalent balances by dealing only with financial institutions with credit ratings of at least A or equivalent. The primary credit exposures for the Group are its receivables generated by the sale of crude oil and natural gas 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. During the financial year 2023, the Group\u2019s crude sales were predominantly made to international oil market participants including the oil majors and trading houses. In November 2023, the Group entered into oil marketing and offtake contracts with Glencore for the Group\u2019s crude oil entitlements from the Jubilee and Ten fields in Ghana and the Rabi Light entitlements in Gabon. JV Partners are predominantly international major oil and gas market participants. Counterparty evaluations are conducted utilising international credit rating agency and financial assessments. Where considered appropriate, security in the form of trade finance instruments from financial 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 significant credit risk exposure to any single counterparty or any group of counterparties. The maximum financial exposure due to credit risk on the Group\u2019s financial assets, representing the sum of cash and cash equivalents, investments, derivative assets, trade receivables, and receivables from Joint Venture Partners, as at 31 December 2023 was $1,373.1 million (2022: $1,438.7 million). ", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-418": { "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 financial derivatives. There were no foreign currency financial derivatives in place as at 31 December 2023 (2022: 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 2023, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.7 million in non-US dollar-denominated cash and cash equivalents (2022: $58.1 million). The following table demonstrates the sensitivity of the Group\u2019s financial instruments to reasonably possible movements in US dollar exchange rates:
Effect on profit before tax
Effect on equity
2023 2022 2023 2022
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.1
9.7
1.1
9.7
US$/foreign currency exchange rates
(20%)
(1.7)
(14.5)
(1.7)
(14.7)
", "dimensions": { "concept": "tullowoilplc:DisclosureOfForeignCurrencyRisk", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-373": { "value": "
Note 18. 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
31 31 31 31
December December December December
Right-of-use assets (included within property, plant and equipment) 2023 2022 2023 2022
and lease liabilities $m $m $m $m
Property leases
22.0
39.2
27.6
34.6
Oil and gas production and support equipment leases
576.9
639.0
826.4
942.4
Transportation equipment leases
25.1
3.4
52.7
7.1
Total
624.0
681.6
906.7
984.1
Current
185.7
251.2
Non-current
721.0
732.9
Total
906.7
984.1
Additions to the right-of-use assets during the 2023 financial year were $81.1 million. Refer to note 9.
For ageing of lease liabilities, refer to note 17.
TEN FPSO
The Group\u2019s leases balance includes the TEN FPSO, classified as \u2018Oil and Gas production and support equipment\u2019. During
the year, the assumption that the TEN FPSO lease term would end in April 2024, when the purchase option was assumed
to be exercised, was updated to reflect the best estimate view that the FPSO will continue to be leased until the cessation
of production in 2032. It also assumes an exercise of the extension option.
The resulting lease liability remeasurement had the following impact on the balances:
$m
Lease liability
(39.2)
Right-of-use asset (included within Property, plant and equipment)
25.6
Amounts due from Joint Venture Partners
13.6
As at 31 December 2023, the present value of the TEN FPSO right-of-use asset was $549.0 million (2022: $596.9 million).
The present value of the TEN FPSO gross lease liability was $763.5 million (2022: $847.9 million).
A receivable from the Joint Venture Partners of $288.8 million (2022: $330.1 million) was recognised in other assets
(note 10) to reflect 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 finance income.
Carrying amounts of the lease liabilities and Joint Venture leases receivables and the movements during the period:
Joint
Venture
Lease lease
liabilities receivables Total
$m $m $m
At 1 January 2022
(1,163.4)
531.0
(632.4)
Additions and changes in lease estimates
(89.4)
40.2
(49.2)
Acquisitions
\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 1 January 2023
(984.1)
376.1
(608.0)
Additions and changes in lease estimates
(174.1)
79.8
(94.3)
Payments/(receipts)
331.5
(136.5)
195.0
Interest (expense)/income
(78.6)
30.1
(48.5)
Currency translation adjustments
(1.4)
\u2013
(1.4)
At 31 December 2023
(906.7)
349.5
(557.2)
ii) Amounts recognised in the statement of profit or loss
31 31
December December
2023 2022
$m $m
Depreciation charge of right-of-use assets
Property leases
7.3
14.0
Oil and gas production and support equipment leases
74.1
46.9
Total
81.4
60.9
Interest expense on lease liabilities (included in finance cost)
78.6
76.4
Interest income on amounts due from Joint Venture Partners
(30.1)
(29.6)
Expense relating to short-term leases
1.0
2.0
Expense relating to leases of low-value assets
0.9
1.8
Total
131.8
111.5
The total net cash outflow for leases in 2023 was $195.0 million (2022: $203.8 million).
", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-374": { "value": "
Note 19. Provisions
Decommiss- Other Decommiss- Other
ioning provisions Total ioning provisions Total
2023 2023 2023 2022 2022 2022
Notes $m $m $m $m $m $m
At 1 January
398.1
116.3
514.4
498.7
228.8
727.5
New provisions, changes in estimates and
reclassifications
47.8
(21.9)
25.9
(47.6)
(19.7)
(67.3)
Acquisitions
\u2013
\u2013
\u2013
24.8
36.8
61.6
Transfer to assets and liabilities held for sale
14
(14.2)
\u2013
(14.2)
Payments
(66.4)
(0.6)
(67.0)
(72.1)
(127.3)
(199.4)
Unwinding of discount
5
10.1
\u2013
10.1
6.0
\u2013
6.0
Currency translation adjustment
2.5
(0.1)
2.4
(11.6)
(2.3)
(13.9)
At 31 December
377.9
93.7
471.6
398.1
116.3
514.4
Current provisions
53.4
14.5
67.9
87.7
11.1
98.8
Non-current provisions
324.5
79.2
403.7
310.4
105.2
415.6
1
1. This relates to an acquisition through business combination discussed in note 15 of the 2022 Annual Report and Accounts.
Other provisions include non-income tax provisions of $38.8 million (2022: $68.3 million) and $54.9 million (2022: $48.0
million) of disputed cases and claims. Management estimates non-current other provisions would fall due between two
and five years.
Non-Current other provisions 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.
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 outflow 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.
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 fields in the foreseeable future. For
Net Zero Emissions sensitivities, including acceleration of decommissioning activities, refer to page 45 of the TCFD and
note 25. Climate change and energy transition.
In 2023, after the extension of several licences in Gabon, the discount rate has increased from 3.5% to 4% for those assets
with an assumed cessation of production date post 2038. This is due to a rate difference between the 10- and 20-year US
Treasury Bills which are used as a data source. This resulted in a decrease in the provision of $3.1 million in Gabon.
Discount Cessation of Discount Cessation of
rate production Total rate production Total
Inflation assumption assumption 2023 assumption assumption 2022
assumption
1
2023 2023 $m 2022 2022 $m
C\u00f4te d\u2019Ivoire
2%
3.5%
2032
47.1
3.5%
2035
45.6
Gabon
2%
3.5\u20134%
2034\u20132047
28.7
3.5%
2025\u20132037
49.2
Ghana
2%
3.5%
2032\u20132036
208.2
3.5%
2036
190.2
Mauritania
n/a
n/a
2018
54.7
n/a
2018
56.0
UK
n/a
n/a
2018
39.2
n/a
2018
57.1
377.9
398.1
1. Short-term inflation rate assumption has decreased from 2.5% to 2.4% in 2024. Medium and long-term rates of 2% remained unchanged from
31 December 2022.
The Group\u2019s decommissioning activities are ongoing in the UK and Mauritania, with $53.4 of the future costs expected
to be incurred in 2024. The remaining activities are planned to continue through to 2027, with an associated expenditure
of $40.4 million.
", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-457": { "value": "Note 19. Provisions
Decommiss- Other Decommiss- Other
ioning provisions Total ioning provisions Total
2023 2023 2023 2022 2022 2022
Notes $m $m $m $m $m $m
At 1 January
398.1
116.3
514.4
498.7
228.8
727.5
New provisions, changes in estimates and
reclassifications
47.8
(21.9)
25.9
(47.6)
(19.7)
(67.3)
Acquisitions
\u2013
\u2013
\u2013
24.8
36.8
61.6
Transfer to assets and liabilities held for sale
14
(14.2)
\u2013
(14.2)
Payments
(66.4)
(0.6)
(67.0)
(72.1)
(127.3)
(199.4)
Unwinding of discount
5
10.1
\u2013
10.1
6.0
\u2013
6.0
Currency translation adjustment
2.5
(0.1)
2.4
(11.6)
(2.3)
(13.9)
At 31 December
377.9
93.7
471.6
398.1
116.3
514.4
Current provisions
53.4
14.5
67.9
87.7
11.1
98.8
Non-current provisions
324.5
79.2
403.7
310.4
105.2
415.6
1 1. This relates to an acquisition through business combination discussed in note 15 of the 2022 Annual Report and Accounts. Other provisions include non-income tax provisions of $38.8 million (2022: $68.3 million) and $54.9 million (2022: $48.0 million) of disputed cases and claims. Management estimates non-current other provisions would fall due between two and five years. Non-Current other provisions 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. 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 outflow 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. 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 fields in the foreseeable future. For Net Zero Emissions sensitivities, including acceleration of decommissioning activities, refer to page 45 of the TCFD and note 25. Climate change and energy transition. In 2023, after the extension of several licences in Gabon, the discount rate has increased from 3.5% to 4% for those assets with an assumed cessation of production date post 2038. This is due to a rate difference between the 10- and 20-year US Treasury Bills which are used as a data source. This resulted in a decrease in the provision of $3.1 million in Gabon.
Discount Cessation of Discount Cessation of
rate production Total rate production Total
Inflation assumption assumption 2023 assumption assumption 2022
assumption
1
2023 2023 $m 2022 2022 $m
C\u00f4te d\u2019Ivoire
2%
3.5%
2032
47.1
3.5%
2035
45.6
Gabon
2%
3.5\u20134%
2034\u20132047
28.7
3.5%
2025\u20132037
49.2
Ghana
2%
3.5%
2032\u20132036
208.2
3.5%
2036
190.2
Mauritania
n/a
n/a
2018
54.7
n/a
2018
56.0
UK
n/a
n/a
2018
39.2
n/a
2018
57.1
377.9
398.1
1. Short-term inflation rate assumption has decreased from 2.5% to 2.4% in 2024. Medium and long-term rates of 2% remained unchanged from 31 December 2022. The Group\u2019s decommissioning activities are ongoing in the UK and Mauritania, with $53.4 of the future costs expected to be incurred in 2024. The remaining activities are planned to continue through to 2027, with an associated expenditure of $40.4 million. Note 23. Commitments and contingencies
2023 2022
$m $m
Capital commitments
207.0
301.2
Contingent liabilities
Performance guarantees
42.7
84.1
Other contingent liabilities
84.4
55.8
127.1
139.9
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 financial obligations. Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash outflow to be higher than remote but not probable. The timing of any economic outflow if it were to occur would likely range between one and five years. The movement in capital commitments is predominantly due to lower capital expenditure budget in Ghana after the start-up of Jubilee South East project in 2023.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-441": { "value": "Note 20. Deferred taxation
Accelerated Other Deferred
tax Decommiss- Tax temporary petroleum
depreciation ioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
(143.6)
\u2013
\u2013
\u2013
\u2013
\u2013
(143.6)
Exchange differences
(0.2)
\u2013
\u2013
\u2013
\u2013
(1.8)
(2.0)
At 1 January 2023
(558.1)
65.9
35.8
(99.0)
15.8
2.6
(537.0)
Credit/(charge) to income statement
117.9
1.7
(28.4)
40.9
\u2013
3.8
135.9
Exchange differences
\u2013
\u2013
\u2013
\u2013
\u2013
0.2
0.2
At 31 December 2023
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
1
2023 2022
$m $m
Deferred tax liabilities
(420.5)
(551.5)
Deferred tax assets
19.6
14.5
(400.9)
(537.0)
1. This relates to an acquisition through business combination discussed in note 15 of the 2022 Annual Report and Accounts. The majority of the Group\u2019s 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 profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability 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:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-419": { "value": "Note 20. Deferred taxation
Accelerated Other Deferred
tax Decommiss- Tax temporary petroleum
depreciation ioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
(143.6)
\u2013
\u2013
\u2013
\u2013
\u2013
(143.6)
Exchange differences
(0.2)
\u2013
\u2013
\u2013
\u2013
(1.8)
(2.0)
At 1 January 2023
(558.1)
65.9
35.8
(99.0)
15.8
2.6
(537.0)
Credit/(charge) to income statement
117.9
1.7
(28.4)
40.9
\u2013
3.8
135.9
Exchange differences
\u2013
\u2013
\u2013
\u2013
\u2013
0.2
0.2
At 31 December 2023
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
1
2023 2022
$m $m
Deferred tax liabilities
(420.5)
(551.5)
Deferred tax assets
19.6
14.5
(400.9)
(537.0)
1. This relates to an acquisition through business combination discussed in note 15 of the 2022 Annual Report and Accounts. The majority of the Group\u2019s 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 profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-375": { "value": "
Note 21. Called-up equity share capital and share premium account
Allotted equity share capital and share premium
Equity share capital Share
allotted and fully paid premium
Number
$m
$m
Ordinary shares of 10p each
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 1 January 2023
1,439,605,995
215.2
1,294.7
Issued during the year
Exercise of share options
12,935,892
1.5
\u2013
At 31 December 2023
1,452,541,887
216.7
1,294.7
The Company does not have a maximum authorised share capital.
", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-420": { "value": "Note 21. Called-up equity share capital and share premium account Allotted equity share capital and share premium
Equity share capital Share
allotted and fully paid premium
Number
$m
$m
Ordinary shares of 10p each
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 1 January 2023
1,439,605,995
215.2
1,294.7
Issued during the year
Exercise of share options
12,935,892
1.5
\u2013
At 31 December 2023
1,452,541,887
216.7
1,294.7
The Company does not have a maximum authorised share capital.", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-376": { "value": "
Note 22. Share-based payments
Analysis of share-based payment charge
2023 2022
Notes $m $m
Tullow Incentive Plan
3.7
3.9
Employee Share Award Plan
1.4
1.2
2022
PDMR buy-out award
0.5
0.5
2021
Tullow Sharesave Plan
0.4
0.2
6.0
5.8
Expensed to operating costs
4
0.4
0.4
Expensed as administrative cost
4
5.6
5.4
Total share-based payment charge
6.0
5.8
The national insurance liability as at 31 December 2023 was $1.9 million (2022: $1.6 million).
Tullow Incentive Plan (TIP)
Under the TIP, senior management can be granted nil exercise price options, normally exercisable from three years (five
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 89 to 113.
The weighted average remaining contractual life for TIP awards outstanding at 31 December 2023 was 6.6 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 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 2023 was 7.1 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.
All remaining options under the SOP expired during 2023 and so there were no outstanding options under the SOP at
31 December 2023.
2020 PDMR buy-out 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 Purchased Shares). These awards will vest after five 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 89 to 113.
The weighted average remaining contractual life for the PDMR Buyout Awards outstanding at 31 December 2023 was 6.5 years.
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 shares 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 2023 had exercise prices of 29p to 40p and remaining contractual lives
between 1.4 years and 3.4 years. The weighted average remaining contractual life is 2.2 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).
Tullow Executive Share Plan (LTIP)
Under the LTIP, senior management can be granted nil exercise price options, normally exercisable between 2.5 to 10
years following grant (with a two-year holding period in the case of the Company\u2019s Directors). Awards granted in 2023
vest subject to Total Shareholder Return (TSR) performance conditions, with 50% of an award subject to an Absolute
TSR performance condition (where the Company\u2019s TSR is tested against targets set by the Remuneration Committee),
and the remaining 50% subject to a relative TSR condition (where the Company\u2019s TSR is compared to the companies
in a Selected Peer Group). Performance is measured over a fixed three-year period of three consecutive financial years
starting with the financial year in which the award is made. The average share price over each weekday within the
previous three months is calculated at the start and at the end of the Performance period. The TSR is calculated from
these averages. An individual must also normally remain in employment to the vesting date in order for the shares to
vest. No dividends are paid over the vesting period; however, it has been agreed for the 2023 LTIP awards that an amount
equivalent to the dividends that would have been paid on the LTIP 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 2023 Tullow Executive Share Plan
(LTIP) awards in the Remuneration Report on pages 89 to 113.
The weighted average remaining contractual life for LTIP awards outstanding at 31 December 2023 was 9.5 years.
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 Granted Exercised Forfeited/ Outstanding Exercisable
as at during during expired during at at
1 January the year the year the year 31 December 31 December
2023
TIP \u2013
number of shares
24,854,248
9,455,309
7,291,530
328,764
26,689,263
6,053,704
2023
TIP \u2013
average weighted share
price at grant
68.4
32.0
75.8
226.3
51.5
51.5
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
2023
ESAP \u2013
number of shares
17,330,077
6,798,244
5,578,281
468,947
18,081,093
8,146,742
2023
ESAP \u2013
average weighted share
price at grant
76.4
32.3
59.9
32.6
66.0
100.2
2022
ESAP \u2013
number of shares
17,638,898
3,556,316
2,803,974
1,061,163
17,3
30,07
7
4,613,422
2022
ESAP \u2013
average weighted share
price at grant
96.5
49.3
180.0
45.2
76.4
228.5
2023
SOP \u2013
number of shares
178,283
\u2013
\u2013
178,283
\u2013
\u2013
2023
SOP \u2013
WAEP
976.4
\u2013
\u2013
976.4
\u2013
\u2013
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
2023
Buyout Awards \u2013 number of shares
9,000,000
\u2013
\u2013
\u2013
9,000,000
\u2013
2023
Buyout Awards \u2013 WAEP
25.7
\u2013
\u2013
\u2013
25.7
\u2013
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
2023
LTIP
number of shares
\u2013
12,241,264
\u2013
\u2013
12,241,264
\u2013
2023
LTIP
average weighted share
price at grant
\u2013
27.7
\u2013
\u2013
27.7
\u2013
2022
LTIP
number of shares
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
2022
LTIP
average weighted share
price at grant
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
2023
SAYE \u2013
number of options
1,534,241
975,600
\u2013
121,970
2,387,871
\u2013
2023
SAYE \u2013
WAEP
38.0
40.0
\u2013
38.2
38.8
\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
The options granted during the year were valued using Monte Carlo simulation models for the LTIP and a proprietary
binomial valuation for the TIP, ESAP and SAYE.
The following table details the weighted average fair value of awards granted and the assumptions used in the fair value
expense calculations.
2023
2023
LTIP
ESAP
2022
ESAP
2023
TIP
2022
TIP
2023
SAYE
2022
SAYE
Weighted average fair value of awards granted
13.4p
32.0p
49.3p
32.0p
49.1p
20.5p
23.1p
Principal inputs to options valuations model:
Weighted average share price at grant
27.7p
32.0p
49.3p
32.0p
49.1p
32.3p
38.4p
Weighted average exercise price
0.0p
0.0p
0.0p
0.0p
0.0p
29.0p
40.0p
Risk-free interest rate per annum
5.0%
3.5%
1.5% to 4.4%
3.5%
1.5%/1.5%
4.5%
4.3%
Expected volatility per annum
63%
89%
101%
to 102%
89%/84%
102%/85%
92%
91%
Expected award life (years)
2.7
3.0
3.0
3.0/5.0
3.0/5
.0
3.6
3.6
Dividend yield per annum
n/a
n/a
n/a
n/a
n/a
0.0%
0.0%
Employee turnover before vesting per annum
0%
5%
5%
5%/0%
5%/0%
5%
5%
1
1,2
1,3
4
1
1. Shows the assumption for 2023 and 2022 LTIP 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 2023 ESAP and TIP Awards, and the 2022 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 2023 LTIP, ESAP and TIP Awards as a dividend equivalent will be payable
on the exercise of these awards.
2023 2023
ESAP TIP
Weighted average share price at exercise for awards exercised
32.3p
32.8p
", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-421": { "value": "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 Granted Exercised Forfeited/ Outstanding Exercisable
as at during during expired during at at
1 January the year the year the year 31 December 31 December
2023
TIP \u2013
number of shares
24,854,248
9,455,309
7,291,530
328,764
26,689,263
6,053,704
2023
TIP \u2013
average weighted share
price at grant
68.4
32.0
75.8
226.3
51.5
51.5
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
2023
ESAP \u2013
number of shares
17,330,077
6,798,244
5,578,281
468,947
18,081,093
8,146,742
2023
ESAP \u2013
average weighted share
price at grant
76.4
32.3
59.9
32.6
66.0
100.2
2022
ESAP \u2013
number of shares
17,638,898
3,556,316
2,803,974
1,061,163
17,3
30,07
7
4,613,422
2022
ESAP \u2013
average weighted share
price at grant
96.5
49.3
180.0
45.2
76.4
228.5
2023
SOP \u2013
number of shares
178,283
\u2013
\u2013
178,283
\u2013
\u2013
2023
SOP \u2013
WAEP
976.4
\u2013
\u2013
976.4
\u2013
\u2013
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
2023
Buyout Awards \u2013 number of shares
9,000,000
\u2013
\u2013
\u2013
9,000,000
\u2013
2023
Buyout Awards \u2013 WAEP
25.7
\u2013
\u2013
\u2013
25.7
\u2013
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
2023
LTIP
number of shares
\u2013
12,241,264
\u2013
\u2013
12,241,264
\u2013
2023
LTIP
average weighted share
price at grant
\u2013
27.7
\u2013
\u2013
27.7
\u2013
2022
LTIP
number of shares
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
2022
LTIP
average weighted share
price at grant
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
2023
SAYE \u2013
number of options
1,534,241
975,600
\u2013
121,970
2,387,871
\u2013
2023
SAYE \u2013
WAEP
38.0
40.0
\u2013
38.2
38.8
\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
", "dimensions": { "concept": "ifrs-full:DisclosureOfNumberAndWeightedAverageExercisePricesOfShareOptionsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-377": { "value": "
Note 23. Commitments and contingencies
2023 2022
$m $m
Capital commitments
207.0
301.2
Contingent liabilities
Performance guarantees
42.7
84.1
Other contingent liabilities
84.4
55.8
127.1
139.9
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
financial obligations.
Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood
of a cash outflow to be higher than remote but not probable. The timing of any economic outflow if it were to occur
would likely range between one and five years.
The movement in capital commitments is predominantly due to lower capital expenditure budget in Ghana after the
start-up of Jubilee South East project in 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-442": { "value": "Note 23. Commitments and contingencies
2023 2022
$m $m
Capital commitments
207.0
301.2
Contingent liabilities
Performance guarantees
42.7
84.1
Other contingent liabilities
84.4
55.8
127.1
139.9
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 financial obligations. Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash outflow to be higher than remote but not probable. The timing of any economic outflow if it were to occur would likely range between one and five years. The movement in capital commitments is predominantly due to lower capital expenditure budget in Ghana after the start-up of Jubilee South East project in 2023.", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-422": { "value": "Note 23. Commitments and contingencies
2023 2022
$m $m
Capital commitments
207.0
301.2
Contingent liabilities
Performance guarantees
42.7
84.1
Other contingent liabilities
84.4
55.8
127.1
139.9
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 financial obligations. Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash outflow to be higher than remote but not probable. The timing of any economic outflow if it were to occur would likely range between one and five years. The movement in capital commitments is predominantly due to lower capital expenditure budget in Ghana after the start-up of Jubilee South East project in 2023.", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-378": { "value": "
Note 24. Related party transactions
The Directors of Tullow Oil plc are considered to be the only Key Management Personnel as defined by IAS 24 Related
Party Disclosures.
2023 2022
$m $m
Short-term employee benefits
2.7
2.5
Post-employment benefits
0.2
0.1
Share-based payments
1.4
1.4
4.3
4.0
Short-term employee benefits
These amounts comprise fees paid to the Directors in respect of salary and benefits earned during the relevant financial
year, plus bonuses awarded for the year.
Post-employment benefits
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 89 to 113.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-443": { "value": "Note 24. Related party transactions The Directors of Tullow Oil plc are considered to be the only Key Management Personnel as defined by IAS 24 Related Party Disclosures.
2023 2022
$m $m
Short-term employee benefits
2.7
2.5
Post-employment benefits
0.2
0.1
Share-based payments
1.4
1.4
4.3
4.0
Short-term employee benefits These amounts comprise fees paid to the Directors in respect of salary and benefits earned during the relevant financial year, plus bonuses awarded for the year. Post-employment benefits 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 89 to 113.", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-423": { "value": "Note 24. Related party transactions The Directors of Tullow Oil plc are considered to be the only Key Management Personnel as defined by IAS 24 Related Party Disclosures.
2023 2022
$m $m
Short-term employee benefits
2.7
2.5
Post-employment benefits
0.2
0.1
Share-based payments
1.4
1.4
4.3
4.0
Short-term employee benefits These amounts comprise fees paid to the Directors in respect of salary and benefits earned during the relevant financial year, plus bonuses awarded for the year. Post-employment benefits 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 89 to 113.", "dimensions": { "concept": "ifrs-full:DisclosureOfTransactionsBetweenRelatedPartiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-379": { "value": "
Note 25. Climate change and energy transition
Tullow remains committed to being Net Zero on Scope 1 and Scope 2 emissions on a net equity basis by 2030, providing
support to host country governments in meeting their national targets by reducing GHG emissions. Further information
on the Group\u2019s Net Zero strategy is on page 33.
This note describes how the Group has considered climate-related impacts in key areas of the Financial Statements
and how this translates into the valuation of assets and measurement of liabilities as Tullow make progress in the energy
transition.
Note (af) 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 on the Group Balance Sheet as at 31 December 2023. Where relevant this note contains references to other
notes to the Group Financial Statements, and sections of the Task Force on Climate-related Financial Disclosures (TCFD),
to provide an overarching summary.
Financial planning assumptions
Tullow targets being Net Zero Scope 1 and 2 emissions by 2030, on a net equity basis, with an interim target of 40%
reduction in emissions by 2025, these metrics have been included in the Group\u2019s business plan. The Financial 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 TCFD on pages 38 to 47 for details).
Tullow continues to assess operating cash flow (OCF) impact on our currently producing assets using the oil price
assumptions within the IEA scenarios which are detailed on pages 43 to 45 of the TCFD.
The impact of acute and chronic physical climate risks on our existing assets are also assessed and meteorological and
climate conditions are incorporated into operational design considerations, please refer to the TCFD on pages 38 to 47
for probabilities, potential exposures, and mitigations.
While carbon prices are projected to grow, there is low likelihood that there will be a substantive impact on the Group\u2019s
core geographies in the medium term. Tullow runs shadow carbon price sensitivities for any new investment decisions
and business planning cycles, using an internal shadow carbon price of $25/tCO
2
e which is in line with the NZE carbon
price for other emerging market and developing economies.
To address hard to abate residual emissions, Tullow is developing a nature-based carbon offset project with the Forestry
Commission of Ghana which is expected to progress towards FID in 2024. The carbon price sensitivity and 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 expected cash flows associated with current nature based solutions are not directly attributable to the
asset CGUs.
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 \u2018Net Zero Emissions by 2050 Scenario\u2019 to assess potential financial
impacts on intangible exploration and evaluation asset write-offs, impairments of property, plant and equipment, and
decommissioning timelines. These are detailed on pages 38 to 47 of the TCFD.
Governmental and societal responses to climate change risks are still developing, and are interdependent upon each
other, and consequently financial statements cannot capture all possible future outcomes as these are not yet known.
", "dimensions": { "concept": "tullowoilplc:DisclosureOfClimateChangeAndEnergyTransition", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-380": { "value": "
Note 26. Events since 31 December 2023
Gabon \u2013 On 29 February 2024, Tullow completed the Asset Swap agreement (ASA) transaction (discussed in note
14. Assets and liabilities classified as held for sale) with Perenco Oil and Gas Gabon S.A (Perenco). The transaction is
a cashless asset swap to be achieved through the exchange of participating interests held by both parties in certain
licences in Gabon. Management have determined that the acquisition of the additional interest in the Tchatamba licence
is a Business Combination and the financial impacts cannot be disclosed in the Annual Report and Accounts as the
measurement of the assets acquired is now underway. Accordingly, the relevant disclosure will be made in the 2024 half
year results.
Kenya \u2013 On 1 March 2024 Tullow received a letter from the EPRA extending the review period of the updated Field
Development Plan to 30 June 2024.
There have not been any other events since 31 December 2023 that have resulted in a material impact on the year-end results.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-424": { "value": "Note 26. Events since 31 December 2023 Gabon \u2013 On 29 February 2024, Tullow completed the Asset Swap agreement (ASA) transaction (discussed in note 14. Assets and liabilities classified as held for sale) with Perenco Oil and Gas Gabon S.A (Perenco). The transaction is a cashless asset swap to be achieved through the exchange of participating interests held by both parties in certain licences in Gabon. Management have determined that the acquisition of the additional interest in the Tchatamba licence is a Business Combination and the financial impacts cannot be disclosed in the Annual Report and Accounts as the measurement of the assets acquired is now underway. Accordingly, the relevant disclosure will be made in the 2024 half year results. Kenya \u2013 On 1 March 2024 Tullow received a letter from the EPRA extending the review period of the updated Field Development Plan to 30 June 2024. There have not been any other events since 31 December 2023 that have resulted in a material impact on the year-end results.", "dimensions": { "concept": "ifrs-full:DisclosureOfNonadjustingEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-381": { "value": "
Note 27. Cash flow statement reconciliations
2023 2022
Purchases of intangible exploration and evaluation assets $m $m
Additions to intangible exploration and evaluation assets
25.4
39.2
Associated cash flows
Purchases of intangible exploration and evaluation assets
(30.2)
(42.6)
Non-cash movements/presented in other cash flow lines
Movement in working capital
4.8
3.4
2023 2022
Purchases of property, plant and equipment $m $m
Additions to property, plant and equipment
499.5
370.7
Associated cash flows
Purchases of property, plant and equipment
(262.3)
(263.8)
Non-cash movements/presented in other cash flow lines
Decommissioning asset revisions
(47.8)
19.9
Right-of-use asset additions
(81.1)
(63.5)
Movement in working capital
(108.3)
(63.3)
2023 2022 2021 2023 2022
Movement in borrowings $m $m $m Movement Movement
Borrowings
2,084.6
2,472.8
2,568.7
(388.2)
(95.9)
Associated cash flows
Debt arrangement fees
(5.0)
\u2013
Repayment of borrowings
(432.2)
(100.0)
Drawdown of borrowings
129.7
\u2013
Non-cash movements/presented in other cash flow lines
Gain on bond buyback
(86.0)
\u2013
Amortisation of arrangement fees and accrued interest
5.3
4.1
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-383": { "value": "
Note 28. Dividends
In 2023, the Board recommended that no interim or final dividend would be paid.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-451": { "value": "Note 29. Tullow Oil plc subsidiaries As at 31 December 2023 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.
Country of
Company name
incorporation
Direct or indirect
Address of registered office
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 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
3232
2, 4th Floor Century Yard, Cricket
Square, George Town, KY1-1209, Cayman Islands
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
1 2 1 2 1. Dissolved 30 January 2024. 2. Dissolved 27 June 2023
Country of Direct or
Company name incorporation
indirect
Address of registered office
Tullow Oil (Mauritania) Ltd
Guernsey
Indirect
P.O. Box 119, Martello Court, Admiral Park,
St. Peter Port GY1 3HB, Guernsey
Tullow Oil Limited
Ireland
Direct
11 Adelaide Road, Dublin 2, Dublin, 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 Gabon 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
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Kenya BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Overseas Holdings BV
Netherlands
Direct
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Suriname BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Uganda Holdings BV
Netherlands
Indirect
Prinses Margrietplantsoen 33,
259
5AM \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
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
Tullow South Africa (Pty) Limited
South Africa
Indirect
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
T.U. S.A.
Uruguay
Indirect
Colonia 810, Of. 403, Montevideo, Uruguay
3 4 5 6 7 3. Dissolved 24 September 2023. 4. Dissolved 22 December 2023. 5. Sold 16 November 2023. 6. Dissolved 22 September 2023. 7. Dissolved 29 March 2023. Note 30. Licence interests Current exploration, development and production interests Ghana
Area Tullow
Licence/Unit area
Fields
sq km
interest
Operator
Other partners
Deepwater Tano Wawa, Tweneboa, 619
54.84%
Tullow
Kosmos, KEGIN, GNPC,
TEN Development Area Enyenra, Ntomme 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
Jubilee, Mahogany, Teak
38.98%
Tullow
Kosmos, KEGIN, GNPC, Jubilee Oil
Holdings, Petro SA
1 1. A unitisation agreement covering the Jubilee field 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 fields. 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
Area Tullow
Licence/Unit area
Fields
sq km
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
DE8
DE8
2,393
40.00%
Perenco
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
Gabon Oil Company
Gwedidi
Gwedidi
5
7.50%
Maurel & Prom
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
Niembi
Niembi
4
7.50%
Maurel & Prom
Gabon Oil Company
Niungo
Niungo
96
40.00%
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
40.00%
Perenco
Tchatamba Marin
Tchatamba Marin
30
40.00%
Perenco
Tchatamba South
Tchatamba South
40
40.00%
Perenco
Tchatamba West
Tchatamba West
25
40.00%
Perenco
2 2 2 2 2 2. Subject to completion of the asset swap deal announced in April 2023 (refer to note 14 above) . Kenya
Area Tullow
Licence
Fields
sq km
interest
Operator
Other partners
Kenya
Block 10BA
11,569
100.00%
Tullow
Block 10BB
Amosing, Ngamia
6,172
100.00%
Tullow
Block 12B
6,200
100.00%
Tullow
Block 13T
Ekales, Twiga
4,719
100.00%
Tullow
3 3 3 Exploration
Area Tullow
Licence/Unit area
Fields
sq km
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
3. Subject to Government of Kenya consent (refer to note 8 above)", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-444": { "value": "Note 29. Tullow Oil plc subsidiaries As at 31 December 2023 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.
Country of
Company name
incorporation
Direct or indirect
Address of registered office
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 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
3232
2, 4th Floor Century Yard, Cricket
Square, George Town, KY1-1209, Cayman Islands
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
1 2 1 2 1. Dissolved 30 January 2024. 2. Dissolved 27 June 2023
Country of Direct or
Company name incorporation
indirect
Address of registered office
Tullow Oil (Mauritania) Ltd
Guernsey
Indirect
P.O. Box 119, Martello Court, Admiral Park,
St. Peter Port GY1 3HB, Guernsey
Tullow Oil Limited
Ireland
Direct
11 Adelaide Road, Dublin 2, Dublin, 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 Gabon 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
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Kenya BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Overseas Holdings BV
Netherlands
Direct
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Suriname BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Uganda Holdings BV
Netherlands
Indirect
Prinses Margrietplantsoen 33,
259
5AM \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
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
Tullow South Africa (Pty) Limited
South Africa
Indirect
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
T.U. S.A.
Uruguay
Indirect
Colonia 810, Of. 403, Montevideo, Uruguay
3 4 5 6 7 3. Dissolved 24 September 2023. 4. Dissolved 22 December 2023. 5. Sold 16 November 2023. 6. Dissolved 22 September 2023. 7. Dissolved 29 March 2023. ", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-425": { "value": "Note 29. Tullow Oil plc subsidiaries As at 31 December 2023 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.
Country of
Company name
incorporation
Direct or indirect
Address of registered office
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 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
3232
2, 4th Floor Century Yard, Cricket
Square, George Town, KY1-1209, Cayman Islands
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
1 2 1 2 1. Dissolved 30 January 2024. 2. Dissolved 27 June 2023
Country of Direct or
Company name incorporation
indirect
Address of registered office
Tullow Oil (Mauritania) Ltd
Guernsey
Indirect
P.O. Box 119, Martello Court, Admiral Park,
St. Peter Port GY1 3HB, Guernsey
Tullow Oil Limited
Ireland
Direct
11 Adelaide Road, Dublin 2, Dublin, 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 Gabon 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
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Kenya BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Overseas Holdings BV
Netherlands
Direct
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Suriname BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Uganda Holdings BV
Netherlands
Indirect
Prinses Margrietplantsoen 33,
259
5AM \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
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
Tullow South Africa (Pty) Limited
South Africa
Indirect
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
T.U. S.A.
Uruguay
Indirect
Colonia 810, Of. 403, Montevideo, Uruguay
3 4 5 6 7 3. Dissolved 24 September 2023. 4. Dissolved 22 December 2023. 5. Sold 16 November 2023. 6. Dissolved 22 September 2023. 7. Dissolved 29 March 2023. ", "dimensions": { "concept": "ifrs-full:DisclosureOfCompositionOfGroupExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-382": { "value": "Note 29. Tullow Oil plc subsidiaries As at 31 December 2023 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.
Country of
Company name
incorporation
Direct or indirect
Address of registered office
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 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
3232
2, 4th Floor Century Yard, Cricket
Square, George Town, KY1-1209, Cayman Islands
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
1 2 1 2 1. Dissolved 30 January 2024. 2. Dissolved 27 June 2023
Country of Direct or
Company name incorporation
indirect
Address of registered office
Tullow Oil (Mauritania) Ltd
Guernsey
Indirect
P.O. Box 119, Martello Court, Admiral Park,
St. Peter Port GY1 3HB, Guernsey
Tullow Oil Limited
Ireland
Direct
11 Adelaide Road, Dublin 2, Dublin, 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 Gabon 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
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Kenya BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Overseas Holdings BV
Netherlands
Direct
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Suriname BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Uganda Holdings BV
Netherlands
Indirect
Prinses Margrietplantsoen 33,
259
5AM \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
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
Tullow South Africa (Pty) Limited
South Africa
Indirect
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
T.U. S.A.
Uruguay
Indirect
Colonia 810, Of. 403, Montevideo, Uruguay
3
4
5
6
7
3. Dissolved 24 September 2023.
4. Dissolved 22 December 2023.
5. Sold 16 November 2023.
6. Dissolved 22 September 2023.
7. Dissolved 29 March 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-384": { "value": "Note 30. Licence interests Current exploration, development and production interests Ghana
Area Tullow
Licence/Unit area
Fields
sq km
interest
Operator
Other partners
Deepwater Tano Wawa, Tweneboa, 619
54.84%
Tullow
Kosmos, KEGIN, GNPC,
TEN Development Area Enyenra, Ntomme 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
Jubilee, Mahogany, Teak
38.98%
Tullow
Kosmos, KEGIN, GNPC, Jubilee Oil
Holdings, Petro SA
1 1. A unitisation agreement covering the Jubilee field 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 fields. 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
Area Tullow
Licence/Unit area
Fields
sq km
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
DE8
DE8
2,393
40.00%
Perenco
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
Gabon Oil Company
Gwedidi
Gwedidi
5
7.50%
Maurel & Prom
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
Niembi
Niembi
4
7.50%
Maurel & Prom
Gabon Oil Company
Niungo
Niungo
96
40.00%
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
40.00%
Perenco
Tchatamba Marin
Tchatamba Marin
30
40.00%
Perenco
Tchatamba South
Tchatamba South
40
40.00%
Perenco
Tchatamba West
Tchatamba West
25
40.00%
Perenco
2 2 2 2 2 2. Subject to completion of the asset swap deal announced in April 2023 (refer to note 14 above) Kenya
Area Tullow
Licence
Fields
sq km
interest
Operator
Other partners
Kenya
Block 10BA
11,569
100.00%
Tullow
Block 10BB
Amosing, Ngamia
6,172
100.00%
Tullow
Block 12B
6,200
100.00%
Tullow
Block 13T
Ekales, Twiga
4,719
100.00%
Tullow
3 3 3 Exploration
Area Tullow
Licence/Unit area
Fields
sq km
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
3. Subject to Government of Kenya consent (refer to note 8 above).", "dimensions": { "concept": "tullowoilplc:DisclosureOfLicenseInterests", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-6": { "value": "Tullow Oil plc", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-325": { "value": "plc", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-7": { "value": "Tullow Oil plc", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } } } }