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(a) General information
Tullow Oil plc is a public limited 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-346": { "value": "(a) General information Tullow Oil plc is a public limited 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. (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 its annual reporting period commencing 1 January 2024: \u2022 Classification of Liabilities as Current or Non-current and Non-current Liabilities with Covenants \u2013 Amendments to IAS 1. \u2022 Lease Liability in a Sale and Leaseback \u2013 Amendments to IFRS 16. \u2022 Disclosure of Supplier Finance Arrangements \u2013 Amendments to IAS 7 and IFRS 7. 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. 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 2024 reporting periods and have not been early adopted by the Group. IFRS 18 Presentation and Disclosure in Financial Statement was issued in April 2024 and is effective for annual reporting periods beginning on or after 1 January 2027. The Group is currently working to identify all impacts the new standard will have on the consolidated Financial Statements and notes to the Financial Statements. The standard has not been early adopted by the Group for the reporting period ending 31 December 2024. Other 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, other than the new addition of goodwill policy described in note (g) below, are consistent with the prior year. (d) Basis of preparation The Financial Statements have been prepared in accordance with United Kingdom 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 Reduced Disclosure Framework (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. 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 The Directors have extended the going concern assessment period to 31 May 2026, aligning with the maturity date of the 2026 senior secured bonds (2026 Notes). The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios covering key judgements and assumptions 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 and the timing of any associated cash outflows. This assessment covers both the Group and the Company. Management has applied the following oil price assumptions for the going concern assessment based on forward prices and market forecasts: Base Case: $70/bbl for 2025; $70/bbl for 2026. Low Case: $65/bbl for 2025; $65/bbl for 2026. To consider the principal risks to the cash flow projections, a sensitivity analysis has been performed which is represented in the Low Case which management considers to be severe, but plausible, given the cumulative impact of the sensitivities applied. The most significant risk would be a sustained decline in oil prices. The analysis has been stress tested by including a 10% production decrease and 5% 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 $67 million outflow being included for the cases expected to progress in the going concern period. Based on the legal opinions received by management, the remaining arbitration cases are not expected to conclude within the going concern period or have remote outcomes, therefore no outflows have been included in that respect in the Low Case. In the event of negative outcomes after the going concern period, management would use all available court processes to appeal such rulings which, based on observable court timelines, would likely take in excess of a further year. The Group is reliant on the continued provision of external financing. The undrawn $250 million revolving credit facility (RCF) and the $1.3 billion 2026 Notes fall due within the going concern period and both will require refinancing to ensure the Group has sufficient liquidity to meet its financial obligations. The Directors intend to complete a holistic refinancing of the existing debt capital structure during 2025. Discussions with banks and commodity traders to secure the refinancing are underway .
A fundamental assumption in concluding that the Group is
a going concern is a successful execution of a holistic
refinancing. The successful execution of a holistic
refinancing is subject to favourable macroeconomic and
market conditions including but not limited to oil price,
credit ratings and accessibility of High Yield Bond markets
and is therefore outside the control of management.
In addition, a binding heads of terms agreement for the
sale of Tullow Oil Gabon SA which holds 100% of Tullow\u2019s
working interest in Gabon for cash consideration of $300
million net of tax has been entered into with Gabon Oil
Company. Signing of a sale and purchase agreement is
targeted for the second quarter of 2025. Completion of
the transaction, which will be subject to relevant
governmental and regulatory approvals, and receipt of the
associated cash proceeds are assumed in June 2025 in the
Base Case, with a three month delay assumed in the Low
Case. Completion of this transaction will materially reduce
the Group\u2019s net debt and is therefore expected to reduce
the risk associated with the holistic debt refinancing.
However, completion and timing of completion of this
transaction are outside the control of management.
Implications and material uncertainties
The Base Case and the Low Case scenarios forecast a
liquidity shortfall in May 2026 when the $1.3 billion 2026
Notes become due for payment, unless the Directors
execute a holistic refinancing of the Group\u2019s debt capital
structure in advance of that date. In addition, the Low Case
scenario forecasts a liquidity shortfall at the end of June
2025, following expiry of the RCF and due to the assumed
delay to the receipt of proceeds from the sale of Tullow Oil
Gabon SA.
The Directors have initiated a process to execute a holistic
refinancing based on proposals received from banks. The
Directors believe this is achievable before the end of June
2025, noting the risks associated with wider market
conditions. If this were not achieved by the end of June
2025 the Directors would continue to pursue such a
refinancing in the second half of 2025 to alleviate the
projected liquidity shortfall in May 2026 and believe this is
achievable, again subject to market conditions.
In addition, if a holistic refinancing was not executed by
the end of June 2025 and receipt of proceeds from the
sale of Tullow Oil Gabon SA was delayed (as assumed in
the Low Case scenario), the Directors plan to enter into
discussions with the lenders under the RCF to extend the
maturity of the facility to align with the timing of completion
of the holistic refinancing or the receipt of proceeds from
the sale of Tullow Oil Gabon SA. Should this not be
possible, the Directors will pursue alternative bridge
financing from commodity traders or secure an alternative
source of financing from private credit markets ahead of
the projected shortfall at the end of June 2025. The
Directors have received unsolicited offers of credit from
such counterparties in excess of the need to alleviate the
projected shortfall and would seek to engage with them
and progress such offers, if required.
The Directors note that despite expressions of interest
from private as well as public parties for participation in the
holistic debt refinancing, implementing a holistic
refinancing is outside the control of the Group. If the
Directors were unable to implement a refinancing
proposal, the ability of the Group to continue trading
would depend upon the Group being able to negotiate a
financial restructuring proposal with its creditors and, if
necessary, that proposal being approved by shareholders.
Whilst the Board would seek to negotiate such a financial
restructuring proposal with its creditors, it is possible that
the creditors would not engage with the Board in those
circumstances. There would therefore be a possible risk of
the Group entering into insolvency proceedings, which the
Directors consider would likely result in limited or no value
being returned to shareholders.
The Directors have concluded that 1) implementing a holistic
refinancing by the end of June 2025 or by May 2026 at the
latest and 2) obtaining sufficient liquidity to cover the expiration
of the RCF at the end of June 2025, if a holistic refinancing is
not implemented by that date, by extending the maturity of
the facility or by completing the sale of Tullow Oil Gabon SA
and receipt of proceeds from the transaction or with alternative
bridge financing, are outside the control of the Group. These
are therefore material uncertainties that may cast significant
doubt over the Group and the Company\u2019s ability to continue
as a going concern. Notwithstanding these material
uncertainties, the Board has confidence in the Group\u2019s ability
to implement a holistic refinancing or extend the RCF or either
complete the sale of Tullow Oil Gabon SA including receipt of
proceeds or seek an alternative source of financing before the
end of June 2025. This is based on the plans in place on the
holistic refinancing, the ongoing support of existing lenders
under the RCF, the binding heads of terms agreement signed
with Gabon Oil Company for the sale of Tullow Oil Gabon SA
and the unsolicited offers of liquidity received from other
sources of finance and credit providers. This is in the context
of the underlying value and cash generation of the Group\u2019s
producing fields to support future debt service and
repayment. On this basis the Board have prepared the
Financial Statements on a going concern basis. The Financial
Statements do not include the adjustments that would result if
the Group and the Company were unable to continue as a
going concern.
(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) Goodwill
The Group allocates goodwill to cash-generating units
(CGUs) that represent the assets acquired as part of the
business combination. Goodwill is tested for impairment
annually as at 31 December and when circumstances
indicate that the carrying value may be impaired.
Impairment is determined for goodwill by assessing the
recoverable amount of each CGU (or group of CGUs) to
which goodwill relates. When the recoverable amount of
the CGU is less than its carrying amount, an impairment
loss is recognised. Impairment losses relating to goodwill
cannot be reversed in future periods.
(h) 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 are 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 (i)) 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\u201360 day terms. For certain non-operated arrangements, the Group\u2019s stake is structured as a carried interest, in which all costs relating to the performance of petroleum operations are borne by the operator and other Joint Venture Partners and are recovered upon production. The recognition of revenue is on net basis, where the Group only accounts for its share of 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. (i) 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 in 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. (j) 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. (k) 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. (l) 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. (m) 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. (n) Commercial reserves and contingent resources Commercial reserves and contingent resources are estimates of the quantities of hydrocarbons that can be economically and legally extracted from the Group\u2019s oil and gas properties. The Group estimates its reserves and resources based on information compiled by appropriately qualified persons relating to the geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery rates. Commercial 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 recoverable reserves and the proportion of the gross reserves that are attributable to the host government under the terms of the production-sharing contracts. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital costs. The Group estimates and reports reserves and resources in line with the principles contained in the Society of Petroleum Engineers (SPE) Petroleum Resources Management Reporting System (PRMS) framework. As the economic assumptions used may change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change. (o) Depletion and amortisation All expenditure carried in 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.
(p) 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 in 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.
(q) 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.
(r) 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.
(s) Share issue expenses and share
premium account
Costs of share issues are written off against the premium
arising on the issues of share capital.
(t) 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 (ab), 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.
(u) Taxation
Current tax, including UK corporation tax and overseas
corporation tax, is the expected tax to be paid or received
on taxable income or loss for the year, using the tax rates
and laws enacted or substantively enacted at the reporting
date, and any adjustment to tax paid/received in respect
to previous years. 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 asset is recognised if it is probable
that sufficient taxable profit will be available to utilise against
temporary difference. 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 are taxable for UK corporation tax.
The Company assesses whether it is probable that a tax
authority will accept an uncertain tax treatment. If it is not
probable, the Company adjusts its accounting for current
and differed taxes to reflect the uncertainty.
(v) Pensions
Contributions to the Group\u2019s defined contribution pension
schemes are charged to operating profit on an
accrual basis.
(w) 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
in 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 in other comprehensive income will
be immediately reclassified to profit or loss.
(x) 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 or less.
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.
(y) 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.
(z) 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 2024, 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 2024 would be $6.6 million (2023: $nil);
therefore, in line with IFRS 9, credit loss expense
was recognised.
In order to minimise the risk of default, credit risk is
managed on a Group basis (note 17).
(aa) 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.
(ab) 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.
(ac) 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 2024, 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.
(ad) 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.
(ae) Provisions
Provisions are recognised when the Group has a present
obligation (legal or constructive) as a result of a past event,
it is probable that an 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.
Restructuring provisions
Restructuring provisions are recognised only when the
Group has a constructive obligation, which is when:
(i) There is a detailed formal plan that identifies the
business or part of the business concerned, the location
and number of employees affected, the detailed estimate
of the associated costs, and the timeline.
(ii) The employees affected have been notified of the plan\u2019s
main features.
(af) Critical accounting judgements
The Group assesses critical accounting judgements
annually. The following are the critical judgements, apart
from those involving estimations, which are dealt with in
policy (ag), that the Directors have made in the process
of applying the Group\u2019s accounting policies and that have
the most significant effect on the amounts recognised
in the Financial Statements.
Carrying value of intangible exploration and
evaluation assets (note 8)
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 2024 was in the impairment assessment of the
Kenya project and assessing the likelihood of recovery of
the net book value of the asset. Triggers for an impairment
assessment were identified in 2024 following a delay in
farm-down and an extension of the field development plan
review period. Due to the stage of this project being
pre-final investment decision (FID) and only having 2C
resources booked, the impairment 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 identified the following estimation uncertainties,
which require judgement, in respect to the Group\u2019s ability
to realise the net present value (NPV), receiving and
subsequently finalising an acceptable offer from a
strategic partner, obtaining financing for the project, and
government deliverables in the 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 a probability of achieving FID
and therefore the recognition of commercial reserves.
This probability was applied to the unrisked NPV to
determine a risk-adjusted recoverable value, which was
then compared against the net book value of the asset.
Based on this, an impairment of $145.4 million was
recognised in the year ended 31 December 2024. Should
the uncertainties around the project be resolved, there will
be a reversal from the previously recognised impairment
charges of $1,175.2 million. However, if the uncertainties
are not resolved, this can lead to the recognition of
additional impairment of $103.2 million. Further details
on the impairment assessment of Kenya can be found
in note 8.
(ag) Key sources of estimation uncertainty
The key assumptions concerning the future, and other
key sources of estimation uncertainty at the balance sheet
date, that have a significant risk of causing a material
adjustment to the carrying amounts of assets and liabilities
in 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 193).
Details on the impact of these key estimates and
judgements using sensitivity applied to impairment
models can be found in note 9.
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 $80.8 million (2023: $85.0 million) are included
in income tax payable of $79.0 million (2023: $78.3 million),
deferred tax liability of $nil (2023: $nil), and provisions of
$1.8 million (2023: $6.7 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 in 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 these claims, the result would be additional
liabilities of $608.7 million (2023: $1,030.3 million) excluding
interest and penalties which in management\u2019s view
are remote.
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 2024, giving rise to an overall decrease in
provision of $4.2 million and decrease in contingent
liability of $421.6 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.
Two hearings took place in November 2023 and June 2024.
On 24 December 2024, the BPRT Tribunal issued its ruling
to the ICC, which delivered its award on 2 January 2025 with
regard to the BPRT arbitration with the Government of
Ghana. The Tribunal determined that BPRT is not applicable
to Tullow Ghana since it falls outside the tax regime
provided for in the Petroleum Agreements. This means that
Tullow Ghana is not liable to pay the $320.3 million BPRT
assessment issued by the GRA, and Tullow has no future
exposure to BPRT in respect of its operations under the
Petroleum Agreements.
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 parties have
agreed a procedural timetable for the arbitration under
which the first Tribunal hearing will be held in July 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 parties have agreed a procedural timetable for the
arbitration under which the first Tribunal hearing will be
held in November 2025.
The Group continues to engage with the Government
of Ghana with the aim of resolving these tax disputes
on a mutually acceptable basis.
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow
$118 million of tax relief in respect of development costs
incurred by Tullow Bangladesh Limited (TBL). The NBR
subsequently issued a payment demand to TBL in
February 2020 for Taka 3,094 million (c.$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, and a hearing of the merits of the
case were heard by the Tribunal on 20 May 2024.
Final written submissions were made to the Tribunal
in September 2024.
Other items
Other items totalling $192.3 million (2023: $294.0 million)
comprise exposures in respect of claims for corporation
tax from disallowed expenditure or withholding taxes that
are either currently under discussion with the tax
authorities or which arise from 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, management anticipates that there will not be
material cash taxes paid in excess of the amounts
provided for uncertain tax treatments.
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(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 its annual reporting
period commencing 1 January 2024:
\u2022 Classification of Liabilities as Current or Non-current
and Non-current Liabilities with Covenants \u2013
Amendments to IAS 1.
\u2022 Lease Liability in a Sale and Leaseback \u2013 Amendments
to IFRS 16.
\u2022 Disclosure of Supplier Finance Arrangements \u2013
Amendments to IAS 7 and IFRS 7.
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.
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 2024
reporting periods and have not been early adopted by
the Group.
IFRS 18 Presentation and Disclosure in Financial Statement
was issued in April 2024 and is effective for annual reporting
periods beginning on or after 1 January 2027. The Group is
currently working to identify all impacts the new standard
will have on the consolidated Financial Statements and
notes to the Financial Statements. The standard has not
been early adopted by the Group for the reporting period
ending 31 December 2024.
Other 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, other than the new
addition of goodwill policy described in note (g) below, are
consistent with the prior year.
", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-405": { "value": "New International Financial Reporting Standards adopted The Group has applied the following standards and amendments for the first time for its annual reporting period commencing 1 January 2024: \u2022 Classification of Liabilities as Current or Non-current and Non-current Liabilities with Covenants \u2013 Amendments to IAS 1. \u2022 Lease Liability in a Sale and Leaseback \u2013 Amendments to IFRS 16. \u2022 Disclosure of Supplier Finance Arrangements \u2013 Amendments to IAS 7 and IFRS 7. 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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfInitialApplicationOfStandardsOrInterpretations", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-406": { "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 2024 reporting periods and have not been early adopted by the Group. IFRS 18 Presentation and Disclosure in Financial Statement was issued in April 2024 and is effective for annual reporting periods beginning on or after 1 January 2027. The Group is currently working to identify all impacts the new standard will have on the consolidated Financial Statements and notes to the Financial Statements. The standard has not been early adopted by the Group for the reporting period ending 31 December 2024. Other 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-349": { "value": "
(d) Basis of preparation
The Financial Statements have been prepared in
accordance with United Kingdom 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 Reduced Disclosure Framework (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. 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 The Directors have extended the going concern assessment period to 31 May 2026, aligning with the maturity date of the 2026 senior secured bonds (2026 Notes). The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios covering key judgements and assumptions 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 and the timing of any associated cash outflows. This assessment covers both the Group and the Company. Management has applied the following oil price assumptions for the going concern assessment based on forward prices and market forecasts: Base Case: $70/bbl for 2025; $70/bbl for 2026. Low Case: $65/bbl for 2025; $65/bbl for 2026. To consider the principal risks to the cash flow projections, a sensitivity analysis has been performed which is represented in the Low Case which management considers to be severe, but plausible, given the cumulative impact of the sensitivities applied. The most significant risk would be a sustained decline in oil prices. The analysis has been stress tested by including a 10% production decrease and 5% 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 $67 million outflow being included for the cases expected to progress in the going concern period. Based on the legal opinions received by management, the remaining arbitration cases are not expected to conclude within the going concern period or have remote outcomes, therefore no outflows have been included in that respect in the Low Case. In the event of negative outcomes after the going concern period, management would use all available court processes to appeal such rulings which, based on observable court timelines, would likely take in excess of a further year. The Group is reliant on the continued provision of external financing. The undrawn $250 million revolving credit facility (RCF) and the $1.3 billion 2026 Notes fall due within the going concern period and both will require refinancing to ensure the Group has sufficient liquidity to meet its financial obligations. The Directors intend to complete a holistic refinancing of the existing debt capital structure during 2025. Discussions with banks and commodity traders to secure the refinancing are underway A fundamental assumption in concluding that the Group is a going concern is a successful execution of a holistic refinancing. The successful execution of a holistic refinancing is subject to favourable macroeconomic and market conditions including but not limited to oil price, credit ratings and accessibility of High Yield Bond markets and is therefore outside the control of management. In addition, a binding heads of terms agreement for the sale of Tullow Oil Gabon SA which holds 100% of Tullow\u2019s working interest in Gabon for cash consideration of $300 million net of tax has been entered into with Gabon Oil Company. Signing of a sale and purchase agreement is targeted for the second quarter of 2025. Completion of the transaction, which will be subject to relevant governmental and regulatory approvals, and receipt of the associated cash proceeds are assumed in June 2025 in the Base Case, with a three month delay assumed in the Low Case. Completion of this transaction will materially reduce the Group\u2019s net debt and is therefore expected to reduce the risk associated with the holistic debt refinancing. However, completion and timing of completion of this transaction are outside the control of management. Implications and material uncertainties The Base Case and the Low Case scenarios forecast a liquidity shortfall in May 2026 when the $1.3 billion 2026 Notes become due for payment, unless the Directors execute a holistic refinancing of the Group\u2019s debt capital structure in advance of that date. In addition, the Low Case scenario forecasts a liquidity shortfall at the end of June 2025, following expiry of the RCF and due to the assumed delay to the receipt of proceeds from the sale of Tullow Oil Gabon SA. The Directors have initiated a process to execute a holistic refinancing based on proposals received from banks. The Directors believe this is achievable before the end of June 2025, noting the risks associated with wider market conditions. If this were not achieved by the end of June 2025 the Directors would continue to pursue such a refinancing in the second half of 2025 to alleviate the projected liquidity shortfall in May 2026 and believe this is achievable, again subject to market conditions. In addition, if a holistic refinancing was not executed by the end of June 2025 and receipt of proceeds from the sale of Tullow Oil Gabon SA was delayed (as assumed in the Low Case scenario), the Directors plan to enter into discussions with the lenders under the RCF to extend the maturity of the facility to align with the timing of completion of the holistic refinancing or the receipt of proceeds from the sale of Tullow Oil Gabon SA. Should this not be possible, the Directors will pursue alternative bridge financing from commodity traders or secure an alternative source of financing from private credit markets ahead of the projected shortfall at the end of June 2025. The Directors have received unsolicited offers of credit from such counterparties in excess of the need to alleviate the projected shortfall and would seek to engage with them and progress such offers, if required. The Directors note that despite expressions of interest from private as well as public parties for participation in the holistic debt refinancing, implementing a holistic refinancing is outside the control of the Group. If the Directors were unable to implement a refinancing proposal, the ability of the Group to continue trading would depend upon the Group being able to negotiate a financial restructuring proposal with its creditors and, if necessary, that proposal being approved by shareholders. Whilst the Board would seek to negotiate such a financial restructuring proposal with its creditors, it is possible that the creditors would not engage with the Board in those circumstances. There would therefore be a possible risk of the Group entering into insolvency proceedings, which the Directors consider would likely result in limited or no value being returned to shareholders. The Directors have concluded that 1) implementing a holistic refinancing by the end of June 2025 or by May 2026 at the latest and 2) obtaining sufficient liquidity to cover the expiration of the RCF at the end of June 2025, if a holistic refinancing is not implemented by that date, by extending the maturity of the facility or by completing the sale of Tullow Oil Gabon SA and receipt of proceeds from the transaction or with alternative bridge financing, are outside the control of the Group. These are therefore material uncertainties that may cast significant doubt over the Group and the Company\u2019s ability to continue as a going concern. Notwithstanding these material uncertainties, the Board has confidence in the Group\u2019s ability to implement a holistic refinancing or extend the RCF or either complete the sale of Tullow Oil Gabon SA including receipt of proceeds or seek an alternative source of financing before the end of June 2025. This is based on the plans in place on the holistic refinancing, the ongoing support of existing lenders under the RCF, the binding heads of terms agreement signed with Gabon Oil Company for the sale of Tullow Oil Gabon SA and the unsolicited offers of liquidity received from other sources of finance and credit providers. This is in the context of the underlying value and cash generation of the Group\u2019s producing fields to support future debt service and repayment. On this basis the Board have prepared the Financial Statements on a going concern basis. The Financial Statements do not include the adjustments that would result if the Group and the Company were unable to continue as a going concern. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-407": { "value": "The Financial Statements have been prepared in accordance with United Kingdom 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-408": { "value": "
Liquidity risk management and going concern
The Directors have extended the going concern assessment
period to 31 May 2026, aligning with the maturity date of the
2026 senior secured bonds (2026 Notes). The Group closely
monitors and manages its liquidity headroom. Cash forecasts
are regularly produced, and sensitivities run for different
scenarios covering key judgements and assumptions
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 and
the timing of any associated cash outflows. This assessment
covers both the Group and the Company.
Management has applied the following oil price
assumptions for the going concern assessment based on
forward prices and market forecasts:
Base Case: $70/bbl for 2025; $70/bbl for 2026.
Low Case: $65/bbl for 2025; $65/bbl for 2026.
To consider the principal risks to the cash flow projections, a
sensitivity analysis has been performed which is represented
in the Low Case which management considers to be severe,
but plausible, given the cumulative impact of the sensitivities
applied. The most significant risk would be a sustained
decline in oil prices. The analysis has been stress tested by
including a 10% production decrease and 5% 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 $67 million outflow being included for the cases
expected to progress in the going concern period. Based on
the legal opinions received by management, the remaining
arbitration cases are not expected to conclude within the
going concern period or have remote outcomes, therefore
no outflows have been included in that respect in the Low
Case. In the event of negative outcomes after the going
concern period, management would use all available court
processes to appeal such rulings which, based on observable
court timelines, would likely take in excess of a further year.
The Group is reliant on the continued provision of external
financing. The undrawn $250 million revolving credit
facility (RCF) and the $1.3 billion 2026 Notes fall due within
the going concern period and both will require refinancing
to ensure the Group has sufficient liquidity to meet its
financial obligations. The Directors intend to complete a
holistic refinancing of the existing debt capital structure
during 2025. Discussions with banks and commodity
traders to secure the refinancing are underway .
A fundamental assumption in concluding that the Group is a going concern is a successful execution of a holistic refinancing. The successful execution of a holistic refinancing is subject to favourable macroeconomic and market conditions including but not limited to oil price, credit ratings and accessibility of High Yield Bond markets and is therefore outside the control of management. In addition, a binding heads of terms agreement for the sale of Tullow Oil Gabon SA which holds 100% of Tullow\u2019s working interest in Gabon for cash consideration of $300 million net of tax has been entered into with Gabon Oil Company. Signing of a sale and purchase agreement is targeted for the second quarter of 2025. Completion of the transaction, which will be subject to relevant governmental and regulatory approvals, and receipt of the associated cash proceeds are assumed in June 2025 in the Base Case, with a three month delay assumed in the Low Case. Completion of this transaction will materially reduce the Group\u2019s net debt and is therefore expected to reduce the risk associated with the holistic debt refinancing. However, completion and timing of completion of this transaction are outside the control of management. Implications and material uncertainties The Base Case and the Low Case scenarios forecast a liquidity shortfall in May 2026 when the $1.3 billion 2026 Notes become due for payment, unless the Directors execute a holistic refinancing of the Group\u2019s debt capital structure in advance of that date. In addition, the Low Case scenario forecasts a liquidity shortfall at the end of June 2025, following expiry of the RCF and due to the assumed delay to the receipt of proceeds from the sale of Tullow Oil Gabon SA. The Directors have initiated a process to execute a holistic refinancing based on proposals received from banks. The Directors believe this is achievable before the end of June 2025, noting the risks associated with wider market conditions. If this were not achieved by the end of June 2025 the Directors would continue to pursue such a refinancing in the second half of 2025 to alleviate the projected liquidity shortfall in May 2026 and believe this is achievable, again subject to market conditions. In addition, if a holistic refinancing was not executed by the end of June 2025 and receipt of proceeds from the sale of Tullow Oil Gabon SA was delayed (as assumed in the Low Case scenario), the Directors plan to enter into discussions with the lenders under the RCF to extend the maturity of the facility to align with the timing of completion of the holistic refinancing or the receipt of proceeds from the sale of Tullow Oil Gabon SA. Should this not be possible, the Directors will pursue alternative bridge financing from commodity traders or secure an alternative source of financing from private credit markets ahead of the projected shortfall at the end of June 2025. The Directors have received unsolicited offers of credit from such counterparties in excess of the need to alleviate the projected shortfall and would seek to engage with them and progress such offers, if required. The Directors note that despite expressions of interest from private as well as public parties for participation in the holistic debt refinancing, implementing a holistic refinancing is outside the control of the Group. If the Directors were unable to implement a refinancing proposal, the ability of the Group to continue trading would depend upon the Group being able to negotiate a financial restructuring proposal with its creditors and, if necessary, that proposal being approved by shareholders. Whilst the Board would seek to negotiate such a financial restructuring proposal with its creditors, it is possible that the creditors would not engage with the Board in those circumstances. There would therefore be a possible risk of the Group entering into insolvency proceedings, which the Directors consider would likely result in limited or no value being returned to shareholders. The Directors have concluded that 1) implementing a holistic refinancing by the end of June 2025 or by May 2026 at the latest and 2) obtaining sufficient liquidity to cover the expiration of the RCF at the end of June 2025, if a holistic refinancing is not implemented by that date, by extending the maturity of the facility or by completing the sale of Tullow Oil Gabon SA and receipt of proceeds from the transaction or with alternative bridge financing, are outside the control of the Group. These are therefore material uncertainties that may cast significant doubt over the Group and the Company\u2019s ability to continue as a going concern. Notwithstanding these material uncertainties, the Board has confidence in the Group\u2019s ability to implement a holistic refinancing or extend the RCF or either complete the sale of Tullow Oil Gabon SA including receipt of proceeds or seek an alternative source of financing before the end of June 2025. This is based on the plans in place on the holistic refinancing, the ongoing support of existing lenders under the RCF, the binding heads of terms agreement signed with Gabon Oil Company for the sale of Tullow Oil Gabon SA and the unsolicited offers of liquidity received from other sources of finance and credit providers. This is in the context of the underlying value and cash generation of the Group\u2019s producing fields to support future debt service and repayment. On this basis the Board have prepared the Financial Statements on a going concern basis. The Financial Statements do not include the adjustments that would result if the Group and the Company were unable to continue as a going concern. ", "dimensions": { "concept": "ifrs-full:DisclosureOfGoingConcernExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-445": { "value": "Liquidity risk management and going concern The Directors have extended the going concern assessment period to 31 May 2026, aligning with the maturity date of the 2026 senior secured bonds (2026 Notes). The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios covering key judgements and assumptions 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 and the timing of any associated cash outflows. This assessment covers both the Group and the Company. Management has applied the following oil price assumptions for the going concern assessment based on forward prices and market forecasts: Base Case: $70/bbl for 2025; $70/bbl for 2026. Low Case: $65/bbl for 2025; $65/bbl for 2026. To consider the principal risks to the cash flow projections, a sensitivity analysis has been performed which is represented in the Low Case which management considers to be severe, but plausible, given the cumulative impact of the sensitivities applied. The most significant risk would be a sustained decline in oil prices. The analysis has been stress tested by including a 10% production decrease and 5% 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 $67 million outflow being included for the cases expected to progress in the going concern period. Based on the legal opinions received by management, the remaining arbitration cases are not expected to conclude within the going concern period or have remote outcomes, therefore no outflows have been included in that respect in the Low Case. In the event of negative outcomes after the going concern period, management would use all available court processes to appeal such rulings which, based on observable court timelines, would likely take in excess of a further year. The Group is reliant on the continued provision of external financing. The undrawn $250 million revolving credit facility (RCF) and the $1.3 billion 2026 Notes fall due within the going concern period and both will require refinancing to ensure the Group has sufficient liquidity to meet its financial obligations. The Directors intend to complete a holistic refinancing of the existing debt capital structure during 2025. Discussions with banks and commodity traders to secure the refinancing are underway . A fundamental assumption in concluding that the Group is a going concern is a successful execution of a holistic refinancing. The successful execution of a holistic refinancing is subject to favourable macroeconomic and market conditions including but not limited to oil price, credit ratings and accessibility of High Yield Bond markets and is therefore outside the control of management. In addition, a binding heads of terms agreement for the sale of Tullow Oil Gabon SA which holds 100% of Tullow\u2019s working interest in Gabon for cash consideration of $300 million net of tax has been entered into with Gabon Oil Company. Signing of a sale and purchase agreement is targeted for the second quarter of 2025. Completion of the transaction, which will be subject to relevant governmental and regulatory approvals, and receipt of the associated cash proceeds are assumed in June 2025 in the Base Case, with a three month delay assumed in the Low Case. Completion of this transaction will materially reduce the Group\u2019s net debt and is therefore expected to reduce the risk associated with the holistic debt refinancing. However, completion and timing of completion of this transaction are outside the control of management. Implications and material uncertainties The Base Case and the Low Case scenarios forecast a liquidity shortfall in May 2026 when the $1.3 billion 2026 Notes become due for payment, unless the Directors execute a holistic refinancing of the Group\u2019s debt capital structure in advance of that date. In addition, the Low Case scenario forecasts a liquidity shortfall at the end of June 2025, following expiry of the RCF and due to the assumed delay to the receipt of proceeds from the sale of Tullow Oil Gabon SA. The Directors have initiated a process to execute a holistic refinancing based on proposals received from banks. The Directors believe this is achievable before the end of June 2025, noting the risks associated with wider market conditions. If this were not achieved by the end of June 2025 the Directors would continue to pursue such a refinancing in the second half of 2025 to alleviate the projected liquidity shortfall in May 2026 and believe this is achievable, again subject to market conditions. In addition, if a holistic refinancing was not executed by the end of June 2025 and receipt of proceeds from the sale of Tullow Oil Gabon SA was delayed (as assumed in the Low Case scenario), the Directors plan to enter into discussions with the lenders under the RCF to extend the maturity of the facility to align with the timing of completion of the holistic refinancing or the receipt of proceeds from the sale of Tullow Oil Gabon SA. Should this not be possible, the Directors will pursue alternative bridge financing from commodity traders or secure an alternative source of financing from private credit markets ahead of the projected shortfall at the end of June 2025. The Directors have received unsolicited offers of credit from such counterparties in excess of the need to alleviate the projected shortfall and would seek to engage with them and progress such offers, if required. The Directors note that despite expressions of interest from private as well as public parties for participation in the holistic debt refinancing, implementing a holistic refinancing is outside the control of the Group. If the Directors were unable to implement a refinancing proposal, the ability of the Group to continue trading would depend upon the Group being able to negotiate a financial restructuring proposal with its creditors and, if necessary, that proposal being approved by shareholders. Whilst the Board would seek to negotiate such a financial restructuring proposal with its creditors, it is possible that the creditors would not engage with the Board in those circumstances. There would therefore be a possible risk of the Group entering into insolvency proceedings, which the Directors consider would likely result in limited or no value being returned to shareholders. The Directors have concluded that 1) implementing a holistic refinancing by the end of June 2025 or by May 2026 at the latest and 2) obtaining sufficient liquidity to cover the expiration of the RCF at the end of June 2025, if a holistic refinancing is not implemented by that date, by extending the maturity of the facility or by completing the sale of Tullow Oil Gabon SA and receipt of proceeds from the transaction or with alternative bridge financing, are outside the control of the Group. These are therefore material uncertainties that may cast significant doubt over the Group and the Company\u2019s ability to continue as a going concern. Notwithstanding these material uncertainties, the Board has confidence in the Group\u2019s ability to implement a holistic refinancing or extend the RCF or either complete the sale of Tullow Oil Gabon SA including receipt of proceeds or seek an alternative source of financing before the end of June 2025. This is based on the plans in place on the holistic refinancing, the ongoing support of existing lenders under the RCF, the binding heads of terms agreement signed with Gabon Oil Company for the sale of Tullow Oil Gabon SA and the unsolicited offers of liquidity received from other sources of finance and credit providers. This is in the context of the underlying value and cash generation of the Group\u2019s producing fields to support future debt service and repayment. On this basis the Board have prepared the Financial Statements on a going concern basis. The Financial Statements do not include the adjustments that would result if the Group and the Company were unable to continue as a going concern. 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 $0.7 billion (2023: $1.0 billion) of total facility headroom and free cash as at 31 December 2024. 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 2024
Non-interest bearing
n/a
99.8
3.2
69.5
84.9
\u2013
257.4
Lease liabilities
16.4%
37.2
38.9
172.8
611.7
213.6
1,074.2
Fixed interest rate instruments
9.8%
Principal repayments
\u2013
492.5
100.0
1,285.2
\u2013
1,877.7
Interest charge
\u2013
17.2
136.7
65.8
\u2013
219.7
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
4.8
\u2013
13.5
53.8
\u2013
72.1
Total
141.8
551.8
492.5
2,231.4
213.6
3,631.1
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
7 7.8
520.8
3,093.4
337.5
4,124.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-350": { "value": "(e) Basis of consolidation The consolidated Financial Statements incorporate the Financial Statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power over an investee entity, is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to use its power to affect its returns. The results of subsidiaries acquired or disposed of during the year are included in the Group income statement from the transaction date of acquisition, being the date on which the Group gains control, and will continue to be included until the date that control ceases.
If the Group loses control over a subsidiary, it derecognises
the related assets, liabilities, non-controlling interest and other
components of equity, while any resultant gain or loss is
recognised in 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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-409": { "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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-446": { "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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-410": { "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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-352": { "value": "
(f) Business combinations
The acquisition method of accounting is used to account
for all business combinations, regardless of whether
equity instruments or other assets are acquired. The
consideration transferred for the acquisition comprises:
\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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-447": { "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. (g) Goodwill The Group allocates goodwill to cash-generating units (CGUs) that represent the assets acquired as part of the business combination. Goodwill is tested for impairment annually as at 31 December and when circumstances indicate that the carrying value may be impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU (or group of CGUs) to which goodwill relates. When the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-411": { "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. (g) Goodwill The Group allocates goodwill to cash-generating units (CGUs) that represent the assets acquired as part of the business combination. Goodwill is tested for impairment annually as at 31 December and when circumstances indicate that the carrying value may be impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU (or group of CGUs) to which goodwill relates. When the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-351": { "value": "(g) Goodwill The Group allocates goodwill to cash-generating units (CGUs) that represent the assets acquired as part of the business combination. Goodwill is tested for impairment annually as at 31 December and when circumstances indicate that the carrying value may be impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU (or group of CGUs) to which goodwill relates. When the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods.
(m) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-353": { "value": "(h) 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 are 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 (i)) 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\u201360 day terms.
For certain non-operated arrangements, the Group\u2019s stake
is structured as a carried interest, in which all costs relating
to the performance of petroleum operations are borne by
the operator and other Joint Venture Partners and are
recovered upon production. The recognition of revenue is
on net basis, where the Group only accounts for its share
of 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-354": { "value": "
(i) 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 in 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-355": { "value": "
(j) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-356": { "value": "
(k) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-412": { "value": "(k) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-357": { "value": "
(l) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-413": { "value": "(l) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-448": { "value": "(m) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-414": { "value": "(m) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-358": { "value": "
(n) Commercial reserves and contingent resources
Commercial reserves and contingent resources are estimates
of the quantities of hydrocarbons that can be economically
and legally extracted from the Group\u2019s oil and gas properties.
The Group estimates its reserves and resources based on
information compiled by appropriately qualified persons
relating to the geological and technical data on the size,
depth, shape and grade of the hydrocarbon body and
suitable production techniques and recovery rates.
Commercial 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
recoverable reserves and the proportion of the gross reserves
that are attributable to the host government under the terms
of the production-sharing contracts. Future development
costs are estimated using assumptions as to the number
of wells required to produce the commercial reserves, the
cost of such wells and associated production facilities,
and other capital costs.
The Group estimates and reports reserves and resources in
line with the principles contained in the Society of Petroleum
Engineers (SPE) Petroleum Resources Management Reporting
System (PRMS) framework. As the economic assumptions
used may change and as additional geological information
is obtained during the operation of a field, estimates of
recoverable reserves may change.
", "dimensions": { "concept": "tullowoilplc:DescriptionOfAccountingPolicyForCommercialReservesAndContingentReserves", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-449": { "value": "
(o) Depletion and amortisation
All expenditure carried in 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-415": { "value": "(o) Depletion and amortisation All expenditure carried in 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-359": { "value": "(o) Depletion and amortisation All expenditure carried in 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-361": { "value": "(p) 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 in 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-360": { "value": "(q) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-362": { "value": "(r) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-416": { "value": "(s) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-363": { "value": "(s) 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:DescriptionOfAccountingPolicyForShareIssueExpensesAndSharePremiumAccount", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-465": { "value": "(t) 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 (ab), 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. (w) 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 in 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 in other comprehensive income will be immediately reclassified to profit or loss. (z) 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 2024, 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 2024 would be $6.6 million (2023: $nil); therefore, in line with IFRS 9, credit loss expense was recognised. In order to minimise the risk of default, credit risk is managed on a Group basis (note 17). (ac) 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 2024, 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-417": { "value": "(t) 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 (ab), 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-364": { "value": "(t) 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 (ab), 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-418": { "value": "(u) Taxation Current tax, including UK corporation tax and overseas corporation tax, is the expected tax to be paid or received on taxable income or loss for the year, using the tax rates and laws enacted or substantively enacted at the reporting date, and any adjustment to tax paid/received in respect to previous years. 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 asset is recognised if it is probable that sufficient taxable profit will be available to utilise against temporary difference. 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 are taxable for UK corporation tax. The Company assesses whether it is probable that a tax authority will accept an uncertain tax treatment. If it is not probable, the Company adjusts its accounting for current and differed taxes to reflect the uncertainty. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-365": { "value": "(u) Taxation Current tax, including UK corporation tax and overseas corporation tax, is the expected tax to be paid or received on taxable income or loss for the year, using the tax rates and laws enacted or substantively enacted at the reporting date, and any adjustment to tax paid/received in respect to previous years. 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 asset is recognised if it is probable that sufficient taxable profit will be available to utilise against temporary difference. 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 are taxable for UK corporation tax. The Company assesses whether it is probable that a tax authority will accept an uncertain tax treatment. If it is not probable, the Company adjusts its accounting for current and differed taxes to reflect the uncertainty. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-366": { "value": "(v) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-450": { "value": "(w) 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 in 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 in other comprehensive income will be immediately reclassified to profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-419": { "value": "(w) 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 in 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 in other comprehensive income will be immediately reclassified to profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-367": { "value": "(w) 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 in 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 in other comprehensive income will be immediately reclassified to profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-368": { "value": "(x) 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 or less. 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-369": { "value": "(y) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-451": { "value": "(z) 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 2024, 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 2024 would be $6.6 million (2023: $nil); therefore, in line with IFRS 9, credit loss expense was recognised. In order to minimise the risk of default, credit risk is managed on a Group basis (note 17). (ac) 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 2024, 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-420": { "value": "(z) 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 2024, 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 2024 would be $6.6 million (2023: $nil); therefore, in line with IFRS 9, credit loss expense was recognised. In order to minimise the risk of default, credit risk is managed on a Group basis (note 17). (ac) 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 2024, 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-370": { "value": "(z) 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 2024, 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 2024 would be $6.6 million (2023: $nil); therefore, in line with IFRS 9, credit loss expense was recognised. 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-371": { "value": "(aa) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-421": { "value": "(ab) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-372": { "value": "(ab) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-373": { "value": "(ac) 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 2024, 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-472": { "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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-374": { "value": "(ad) 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-375": { "value": "(ae) Provisions Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an 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. Restructuring provisions Restructuring provisions are recognised only when the Group has a constructive obligation, which is when: (i) There is a detailed formal plan that identifies the business or part of the business concerned, the location and number of employees affected, the detailed estimate of the associated costs, and the timeline. (ii) The employees affected have been notified of the plan\u2019s main features. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForProvisionsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-376": { "value": "(af) Critical accounting judgements The Group assesses critical accounting judgements annually. The following are the critical judgements, apart from those involving estimations, which are dealt with in policy (ag), that the Directors have made in the process of applying the Group\u2019s accounting policies and that have the most significant effect on the amounts recognised in the Financial Statements. Carrying value of intangible exploration and evaluation assets (note 8) 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 2024 was in the impairment assessment of the Kenya project and assessing the likelihood of recovery of the net book value of the asset. Triggers for an impairment assessment were identified in 2024 following a delay in farm-down and an extension of the field development plan review period. Due to the stage of this project being pre-final investment decision (FID) and only having 2C resources booked, the impairment 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 identified the following estimation uncertainties, which require judgement, in respect to the Group\u2019s ability to realise the net present value (NPV), receiving and subsequently finalising an acceptable offer from a strategic partner, obtaining financing for the project, and government deliverables in the 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 a probability of achieving FID and therefore the recognition of commercial reserves. This probability was applied to the unrisked NPV to determine a risk-adjusted recoverable value, which was then compared against the net book value of the asset. Based on this, an impairment of $145.4 million was recognised in the year ended 31 December 2024. Should the uncertainties around the project be resolved, there will be a reversal from the previously recognised impairment charges of $1,175.2 million. However, if the uncertainties are not resolved, this can lead to the recognition of additional impairment of $103.2 million. Further details on the impairment assessment of Kenya can be found in note 8. (ag) Key sources of estimation uncertainty The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities in 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 193). Details on the impact of these key estimates and judgements using sensitivity applied to impairment models can be found in note 9. 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 $80.8 million (2023: $85.0 million) are included in income tax payable of $79.0 million (2023: $78.3 million), deferred tax liability of $nil (2023: $nil), and provisions of $1.8 million (2023: $6.7 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 in 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 these claims, the result would be additional liabilities of $608.7 million (2023: $1,030.3 million) excluding interest and penalties which in management\u2019s view are remote. 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 2024, giving rise to an overall decrease in provision of $4.2 million and decrease in contingent liability of $421.6 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. Two hearings took place in November 2023 and June 2024. On 24 December 2024, the BPRT Tribunal issued its ruling to the ICC, which delivered its award on 2 January 2025 with regard to the BPRT arbitration with the Government of Ghana. The Tribunal determined that BPRT is not applicable to Tullow Ghana since it falls outside the tax regime provided for in the Petroleum Agreements. This means that Tullow Ghana is not liable to pay the $320.3 million BPRT assessment issued by the GRA, and Tullow has no future exposure to BPRT in respect of its operations under the Petroleum Agreements. 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 parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing will be held in July 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 parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing will be held in November 2025. The Group continues to engage with the Government of Ghana with the aim of resolving these tax disputes on a mutually acceptable basis. Bangladesh litigation The National Board of Revenue (NBR) is seeking to disallow $118 million of tax relief in respect of development costs incurred by Tullow Bangladesh Limited (TBL). The NBR subsequently issued a payment demand to TBL in February 2020 for Taka 3,094 million (c.$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, and a hearing of the merits of the case were heard by the Tribunal on 20 May 2024. Final written submissions were made to the Tribunal in September 2024. Other items Other items totalling $192.3 million (2023: $294.0 million) comprise exposures in respect of claims for corporation tax from disallowed expenditure or withholding taxes that are either currently under discussion with the tax authorities or which arise from 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, 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-422": { "value": "(ag) Key sources of estimation uncertainty The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities in 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 193). Details on the impact of these key estimates and judgements using sensitivity applied to impairment models can be found in note 9. 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 $80.8 million (2023: $85.0 million) are included in income tax payable of $79.0 million (2023: $78.3 million), deferred tax liability of $nil (2023: $nil), and provisions of $1.8 million (2023: $6.7 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 in 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 these claims, the result would be additional liabilities of $608.7 million (2023: $1,030.3 million) excluding interest and penalties which in management\u2019s view are remote. 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 2024, giving rise to an overall decrease in provision of $4.2 million and decrease in contingent liability of $421.6 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. Two hearings took place in November 2023 and June 2024. On 24 December 2024, the BPRT Tribunal issued its ruling to the ICC, which delivered its award on 2 January 2025 with regard to the BPRT arbitration with the Government of Ghana. The Tribunal determined that BPRT is not applicable to Tullow Ghana since it falls outside the tax regime provided for in the Petroleum Agreements. This means that Tullow Ghana is not liable to pay the $320.3 million BPRT assessment issued by the GRA, and Tullow has no future exposure to BPRT in respect of its operations under the Petroleum Agreements. 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 parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing will be held in July 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 parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing will be held in November 2025. The Group continues to engage with the Government of Ghana with the aim of resolving these tax disputes on a mutually acceptable basis. Bangladesh litigation The National Board of Revenue (NBR) is seeking to disallow $118 million of tax relief in respect of development costs incurred by Tullow Bangladesh Limited (TBL). The NBR subsequently issued a payment demand to TBL in February 2020 for Taka 3,094 million (c.$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, and a hearing of the merits of the case were heard by the Tribunal on 20 May 2024. Final written submissions were made to the Tribunal in September 2024. Other items Other items totalling $192.3 million (2023: $294.0 million) comprise exposures in respect of claims for corporation tax from disallowed expenditure or withholding taxes that are either currently under discussion with the tax authorities or which arise from 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, 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-377": { "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: Ghana, Non-operated producing assets 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 2024 and 31 December 2023.
Non-
Ghana Operated Kenya Exploration Corporate Total
Notes $m $m $m $m $m $m
2024
Sales revenue by origin
2
1,325.4
283.1
\u2013
\u2013
(73.6)
1,534.9
Segment result
1
722.6
123.5
(145.4)
(55.9)
(91.6)
553.2
Provisions reversal
70.4
Asset revaluation
38.9
Unallocated corporate expenses
2
 (66.9)
Operating profit
595.6
Finance income
71.5
Finance costs
(345.6)
Profit before tax
321.5
Income tax expense
(266.9)
Profit after tax
54.6
Total assets
3,164.3
305.0
112.2
4.9
465.1
4,051.5
Total liabilities
3
(1,978.4)
(254.2)
(5.8)
(6.2)
(2,079.6)
(4,324.2)
Other segment information
Capital expenditure:
Property, plant and equipment
126.4
122.3
2.2
\u2013
2.6
253.5
Intangible exploration and
evaluation assets
0.2
14.3
6.4
13.8
\u2013
34.7
Depletion, depreciation and amortisation
(401.4)
(37.0)
(2.7)
\u2013
(3.1)
(444.2)
Impairment reversal of property, plant
and equipment, net
\u2013
11.8
\u2013
\u2013
\u2013
11.8
Exploration costs written off
\u2013
(11.2)
(145.4)
(56.0)
\u2013
(212.6)
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
2024 2023
$m $m
Segment result
553.2
329.8
Add back:
Exploration costs written off
212.6
27.0
Impairment (reversal)/impairment of property, plant and equipment
(11.8)
408.1
Gross profit
754.0
764.9
All sales are made to external customers. In 2023, Tullow entered an oil marketing contract under which it sells its crude
oil entitlements to Glencore Energy UK Limited. The contract expires in 2028. Revenues arising from this contract from
Ghana and Non-operated segments amounted to approximately $1,501 million in 2024. No other customer contributed
more than 10% of total sales revenue during the year. In 2023, revenues arising from Ghana and Non-operated segments
amounted to approximately $462.3 million, $326.9 million and $181.9 million relating to the Group\u2019s customers, who each
contributed more than 10% of sales revenue.
Non-
Ghana Operated Kenya Exploration Corporate Total
Notes $m $m $m $m $m $m
2023
Sales revenue by origin
2
1,311.4
461.8
\u2013
\u2013
(139.1)
1,634.1
Segment result
1
408.2
114.0
(17.9)
(9.9)
(164.6)
329.8
Provisions reversal
22.0
Other gains
0.2
Unallocated corporate expenses
2
 (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
3
(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. 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
2024 2023 2024 2023
Sales revenue and non-current assets by origin $m $m $m $m
Ghana
1,325.4
1,311.4
2,468.3
2,771.0
Total Ghana
1,325.4
1,311.4
2,468.3
2,771.0
Kenya
\u2013
\u2013
110.9
250.0
Total Kenya
\u2013
\u2013
110.9
250.0
Argentina
\u2013
\u2013
\u2013
36.4
C\u00f4te d\u2019Ivoire
\u2013
\u2013
\u2013
5.8
Total Exploration
\u2013
\u2013
\u2013
42.2
Gabon
247.8
419.5
228.4
82.8
C\u00f4te d\u2019Ivoire
35.3
42.3
\u2013
0.4
Total Non-Operated
283.1
461.8
228.4
83.2
Corporate
(73.6)
(139.1)
11.3
12.0
Total
1,534.9
1,634.1
2,818.9
3,158.4
1. Non-current assets exclude derivative financial instruments and deferred tax assets.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-423": { "value": "
Non- Non-
Sales Sales current current
revenue revenue
assets
1
assets
1
2024 2023 2024 2023
Sales revenue and non-current assets by origin $m $m $m $m
Ghana
1,325.4
1,311.4
2,468.3
2,771.0
Total Ghana
1,325.4
1,311.4
2,468.3
2,771.0
Kenya
\u2013
\u2013
110.9
250.0
Total Kenya
\u2013
\u2013
110.9
250.0
Argentina
\u2013
\u2013
\u2013
36.4
C\u00f4te d\u2019Ivoire
\u2013
\u2013
\u2013
5.8
Total Exploration
\u2013
\u2013
\u2013
42.2
Gabon
247.8
419.5
228.4
82.8
C\u00f4te d\u2019Ivoire
35.3
42.3
\u2013
0.4
Total Non-Operated
283.1
461.8
228.4
83.2
Corporate
(73.6)
(139.1)
11.3
12.0
Total
1,534.9
1,634.1
2,818.9
3,158.4
1. Non-current assets exclude derivative financial instruments and deferred tax assets.", "dimensions": { "concept": "ifrs-full:DisclosureOfGeographicalAreasExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-378": { "value": "
Note 2. Total revenue
2024 2023
$m $m
Revenue from contracts with customers
Revenue from crude oil sales
1,554.5
1,744.6
Revenue from gas sales
54.0
28.6
Total revenue from contracts with customers
1,608.5
1,773.2
Loss on realisation of cash flow hedges
(73.6)
(139.1)
Total revenue
1,534.9
1,634.1
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-424": { "value": "Note 2. Total revenue
2024 2023
$m $m
Revenue from contracts with customers
Revenue from crude oil sales
1,554.5
1,744.6
Revenue from gas sales
54.0
28.6
Total revenue from contracts with customers
1,608.5
1,773.2
Loss on realisation of cash flow hedges
(73.6)
(139.1)
Total revenue
1,534.9
1,634.1
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-379": { "value": "
Note 3. Staff costs
The average annual number of employees employed by the Group worldwide was:
2024 2023
Number Number
Administration
198
187
Technical
204
206
Total
402
393
Staff costs in respect of those employees were as follows:
2024 2023
$m $m
Salaries
73.5
71.5
Social security costs
6.6
7.1
Pension costs
6.2
6.3
Total staff costs
86.3
84.9
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 administrative overhead cost
in the income statement. The net staff costs recognised in the income statement were $12.1 million (2023: $16.5 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 $6.2 million (2023: $6.3 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-380": { "value": "
Note 4. Other costs
2024 2023
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
272.4
292.9
Depletion and amortisation of oil and gas and leased assets
1
9
437.6
430.8
Overlift, underlift and oil stock movements
42.5
109.3
Royalties
27.9
33.9
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
0.1
1.9
Total cost of sales
780.9
869.2
Share-based payment charge included in administrative expenses
22
6.5
5.6
Depreciation of other fixed assets
1
9
6.6
5.8
Other administrative costs
40.1
44.7
Total administrative expenses
53.2
56.1
Provisions reversal
2
(63.3)
(22.0)
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.2
2.0
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.5
Total audit services
2.7
2.5
Non-audit services:
Audit-related assurance services
0.5
0.5
Corporate finance services
0.8
\u2013
Total non-audit services
1.3
0.5
Total
4.0
3.0
1. Depreciation expense on leased assets of $91.4 million (2023: $81.4 million) as per note 9 includes a charge of $4.1 million (2023: $2.2 million) on
leased administrative assets, which is presented in administrative expenses in the income statement. The remaining balance of $87.3 million (2023:
$79.2 million) relates to other leased assets and is included in cost of sales.
2. This includes reduction in other provisions of $70.4 million (2023: $22.0 million) as well as provision for restructuring and redundancy costs of
$7.1 million (2023: $nil).
The decrease in other administrative costs is mainly due to a reduction in one-off corporate project expenditure
and lower insurance premiums partly offset by higher payroll costs 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 33% of audit services during the year. The level of non-audit work was higher in 2024 due to
additional work related to refinancing.
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 page 89. No services were provided pursuant to contingent fee arrangements.
", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-482": { "value": "Note 4. Other costs
2024 2023
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
272.4
292.9
Depletion and amortisation of oil and gas and leased assets
1
9
437.6
430.8
Overlift, underlift and oil stock movements
42.5
109.3
Royalties
27.9
33.9
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
0.1
1.9
Total cost of sales
780.9
869.2
Share-based payment charge included in administrative expenses
22
6.5
5.6
Depreciation of other fixed assets
1
9
6.6
5.8
Other administrative costs
40.1
44.7
Total administrative expenses
53.2
56.1
Provisions reversal
2
(63.3)
(22.0)
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.2
2.0
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.5
Total audit services
2.7
2.5
Non-audit services:
Audit-related assurance services
0.5
0.5
Corporate finance services
0.8
\u2013
Total non-audit services
1.3
0.5
Total
4.0
3.0
1. Depreciation expense on leased assets of $91.4 million (2023: $81.4 million) as per note 9 includes a charge of $4.1 million (2023: $2.2 million) on leased administrative assets, which is presented in administrative expenses in the income statement. The remaining balance of $87.3 million (2023: $79.2 million) relates to other leased assets and is included in cost of sales. 2. This includes reduction in other provisions of $70.4 million (2023: $22.0 million) as well as provision for restructuring and redundancy costs of $7.1 million (2023: $nil). The decrease in other administrative costs is mainly due to a reduction in one-off corporate project expenditure and lower insurance premiums partly offset by higher payroll costs 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 33% of audit services during the year. The level of non-audit work was higher in 2024 due to additional work related to refinancing. 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 page 89. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-478": { "value": "Note 4. Other costs
2024 2023
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
272.4
292.9
Depletion and amortisation of oil and gas and leased assets
1
9
437.6
430.8
Overlift, underlift and oil stock movements
42.5
109.3
Royalties
27.9
33.9
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
0.1
1.9
Total cost of sales
780.9
869.2
Share-based payment charge included in administrative expenses
22
6.5
5.6
Depreciation of other fixed assets
1
9
6.6
5.8
Other administrative costs
40.1
44.7
Total administrative expenses
53.2
56.1
Provisions reversal
2
(63.3)
(22.0)
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.2
2.0
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.5
Total audit services
2.7
2.5
Non-audit services:
Audit-related assurance services
0.5
0.5
Corporate finance services
0.8
\u2013
Total non-audit services
1.3
0.5
Total
4.0
3.0
1. Depreciation expense on leased assets of $91.4 million (2023: $81.4 million) as per note 9 includes a charge of $4.1 million (2023: $2.2 million) on leased administrative assets, which is presented in administrative expenses in the income statement. The remaining balance of $87.3 million (2023: $79.2 million) relates to other leased assets and is included in cost of sales. 2. This includes reduction in other provisions of $70.4 million (2023: $22.0 million) as well as provision for restructuring and redundancy costs of $7.1 million (2023: $nil). The decrease in other administrative costs is mainly due to a reduction in one-off corporate project expenditure and lower insurance premiums partly offset by higher payroll costs 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 33% of audit services during the year. The level of non-audit work was higher in 2024 due to additional work related to refinancing. 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 page 89. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-473": { "value": "Note 4. Other costs
2024 2023
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
272.4
292.9
Depletion and amortisation of oil and gas and leased assets
1
9
437.6
430.8
Overlift, underlift and oil stock movements
42.5
109.3
Royalties
27.9
33.9
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
0.1
1.9
Total cost of sales
780.9
869.2
Share-based payment charge included in administrative expenses
22
6.5
5.6
Depreciation of other fixed assets
1
9
6.6
5.8
Other administrative costs
40.1
44.7
Total administrative expenses
53.2
56.1
Provisions reversal
2
(63.3)
(22.0)
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.2
2.0
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.5
Total audit services
2.7
2.5
Non-audit services:
Audit-related assurance services
0.5
0.5
Corporate finance services
0.8
\u2013
Total non-audit services
1.3
0.5
Total
4.0
3.0
1. Depreciation expense on leased assets of $91.4 million (2023: $81.4 million) as per note 9 includes a charge of $4.1 million (2023: $2.2 million) on leased administrative assets, which is presented in administrative expenses in the income statement. The remaining balance of $87.3 million (2023: $79.2 million) relates to other leased assets and is included in cost of sales. 2. This includes reduction in other provisions of $70.4 million (2023: $22.0 million) as well as provision for restructuring and redundancy costs of $7.1 million (2023: $nil). The decrease in other administrative costs is mainly due to a reduction in one-off corporate project expenditure and lower insurance premiums partly offset by higher payroll costs 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 33% of audit services during the year. The level of non-audit work was higher in 2024 due to additional work related to refinancing. 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 page 89. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-466": { "value": "Note 4. Other costs
2024 2023
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
272.4
292.9
Depletion and amortisation of oil and gas and leased assets
1
9
437.6
430.8
Overlift, underlift and oil stock movements
42.5
109.3
Royalties
27.9
33.9
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
0.1
1.9
Total cost of sales
780.9
869.2
Share-based payment charge included in administrative expenses
22
6.5
5.6
Depreciation of other fixed assets
1
9
6.6
5.8
Other administrative costs
40.1
44.7
Total administrative expenses
53.2
56.1
Provisions reversal
2
(63.3)
(22.0)
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.2
2.0
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.5
Total audit services
2.7
2.5
Non-audit services:
Audit-related assurance services
0.5
0.5
Corporate finance services
0.8
\u2013
Total non-audit services
1.3
0.5
Total
4.0
3.0
1. Depreciation expense on leased assets of $91.4 million (2023: $81.4 million) as per note 9 includes a charge of $4.1 million (2023: $2.2 million) on leased administrative assets, which is presented in administrative expenses in the income statement. The remaining balance of $87.3 million (2023: $79.2 million) relates to other leased assets and is included in cost of sales. 2. This includes reduction in other provisions of $70.4 million (2023: $22.0 million) as well as provision for restructuring and redundancy costs of $7.1 million (2023: $nil). The decrease in other administrative costs is mainly due to a reduction in one-off corporate project expenditure and lower insurance premiums partly offset by higher payroll costs 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 33% of audit services during the year. The level of non-audit work was higher in 2024 due to additional work related to refinancing. 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 page 89. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-452": { "value": "Note 4. Other costs
2024 2023
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
272.4
292.9
Depletion and amortisation of oil and gas and leased assets
1
9
437.6
430.8
Overlift, underlift and oil stock movements
42.5
109.3
Royalties
27.9
33.9
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
0.1
1.9
Total cost of sales
780.9
869.2
Share-based payment charge included in administrative expenses
22
6.5
5.6
Depreciation of other fixed assets
1
9
6.6
5.8
Other administrative costs
40.1
44.7
Total administrative expenses
53.2
56.1
Provisions reversal
2
(63.3)
(22.0)
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.2
2.0
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.5
Total audit services
2.7
2.5
Non-audit services:
Audit-related assurance services
0.5
0.5
Corporate finance services
0.8
\u2013
Total non-audit services
1.3
0.5
Total
4.0
3.0
1. Depreciation expense on leased assets of $91.4 million (2023: $81.4 million) as per note 9 includes a charge of $4.1 million (2023: $2.2 million) on leased administrative assets, which is presented in administrative expenses in the income statement. The remaining balance of $87.3 million (2023: $79.2 million) relates to other leased assets and is included in cost of sales. 2. This includes reduction in other provisions of $70.4 million (2023: $22.0 million) as well as provision for restructuring and redundancy costs of $7.1 million (2023: $nil). The decrease in other administrative costs is mainly due to a reduction in one-off corporate project expenditure and lower insurance premiums partly offset by higher payroll costs 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 33% of audit services during the year. The level of non-audit work was higher in 2024 due to additional work related to refinancing. 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 page 89. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-425": { "value": "Note 4. Other costs
2024 2023
Notes $m $m
Operating profit is stated after charging/(deducting):
Operating costs
272.4
292.9
Depletion and amortisation of oil and gas and leased assets
1
9
437.6
430.8
Overlift, underlift and oil stock movements
42.5
109.3
Royalties
27.9
33.9
Share-based payment charge included in cost of sales
22
0.4
0.4
Other cost of sales
0.1
1.9
Total cost of sales
780.9
869.2
Share-based payment charge included in administrative expenses
22
6.5
5.6
Depreciation of other fixed assets
1
9
6.6
5.8
Other administrative costs
40.1
44.7
Total administrative expenses
53.2
56.1
Provisions reversal
2
(63.3)
(22.0)
Fees payable to the Company\u2019s auditor for:
The audit of the Company\u2019s annual accounts
2.2
2.0
The audit of the Company\u2019s subsidiaries pursuant to legislation
0.5
0.5
Total audit services
2.7
2.5
Non-audit services:
Audit-related assurance services
0.5
0.5
Corporate finance services
0.8
\u2013
Total non-audit services
1.3
0.5
Total
4.0
3.0
1. Depreciation expense on leased assets of $91.4 million (2023: $81.4 million) as per note 9 includes a charge of $4.1 million (2023: $2.2 million) on leased administrative assets, which is presented in administrative expenses in the income statement. The remaining balance of $87.3 million (2023: $79.2 million) relates to other leased assets and is included in cost of sales. 2. This includes reduction in other provisions of $70.4 million (2023: $22.0 million) as well as provision for restructuring and redundancy costs of $7.1 million (2023: $nil). The decrease in other administrative costs is mainly due to a reduction in one-off corporate project expenditure and lower insurance premiums partly offset by higher payroll costs 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 33% of audit services during the year. The level of non-audit work was higher in 2024 due to additional work related to refinancing. 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 page 89. No services were provided pursuant to contingent fee arrangements.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherOperatingIncomeExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-381": { "value": "
Note 5. Net financing costs
2024 2023
Notes $m $m
Interest on bank overdrafts and borrowings
211.5
237.0
Interest on obligations under leases
18
119.7
78.6
Total borrowing costs
331.2
315.6
Finance and arrangement fees
3.0
1.9
Other interest expense
\u2013
2.0
Unwinding of discount on decommissioning provisions
19
11.4
10.1
Total finance costs
345.6
329.6
Interest income on amounts due from Joint Venture Partners for leases
18
(48.1)
(30.1)
Other finance income
(23.4)
(13.9)
Total finance income
(71.5)
(44.0)
Net financing costs
274.1
285.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-479": { "value": "Note 5. Net financing costs
2024 2023
Notes $m $m
Interest on bank overdrafts and borrowings
211.5
237.0
Interest on obligations under leases
18
119.7
78.6
Total borrowing costs
331.2
315.6
Finance and arrangement fees
3.0
1.9
Other interest expense
\u2013
2.0
Unwinding of discount on decommissioning provisions
19
11.4
10.1
Total finance costs
345.6
329.6
Interest income on amounts due from Joint Venture Partners for leases
18
(48.1)
(30.1)
Other finance income
(23.4)
(13.9)
Total finance income
(71.5)
(44.0)
Net financing costs
274.1
285.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-474": { "value": "Note 5. Net financing costs
2024 2023
Notes $m $m
Interest on bank overdrafts and borrowings
211.5
237.0
Interest on obligations under leases
18
119.7
78.6
Total borrowing costs
331.2
315.6
Finance and arrangement fees
3.0
1.9
Other interest expense
\u2013
2.0
Unwinding of discount on decommissioning provisions
19
11.4
10.1
Total finance costs
345.6
329.6
Interest income on amounts due from Joint Venture Partners for leases
18
(48.1)
(30.1)
Other finance income
(23.4)
(13.9)
Total finance income
(71.5)
(44.0)
Net financing costs
274.1
285.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-467": { "value": "Note 5. Net financing costs
2024 2023
Notes $m $m
Interest on bank overdrafts and borrowings
211.5
237.0
Interest on obligations under leases
18
119.7
78.6
Total borrowing costs
331.2
315.6
Finance and arrangement fees
3.0
1.9
Other interest expense
\u2013
2.0
Unwinding of discount on decommissioning provisions
19
11.4
10.1
Total finance costs
345.6
329.6
Interest income on amounts due from Joint Venture Partners for leases
18
(48.1)
(30.1)
Other finance income
(23.4)
(13.9)
Total finance income
(71.5)
(44.0)
Net financing costs
274.1
285.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-453": { "value": "Note 5. Net financing costs
2024 2023
Notes $m $m
Interest on bank overdrafts and borrowings
211.5
237.0
Interest on obligations under leases
18
119.7
78.6
Total borrowing costs
331.2
315.6
Finance and arrangement fees
3.0
1.9
Other interest expense
\u2013
2.0
Unwinding of discount on decommissioning provisions
19
11.4
10.1
Total finance costs
345.6
329.6
Interest income on amounts due from Joint Venture Partners for leases
18
(48.1)
(30.1)
Other finance income
(23.4)
(13.9)
Total finance income
(71.5)
(44.0)
Net financing costs
274.1
285.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-426": { "value": "Note 5. Net financing costs
2024 2023
Notes $m $m
Interest on bank overdrafts and borrowings
211.5
237.0
Interest on obligations under leases
18
119.7
78.6
Total borrowing costs
331.2
315.6
Finance and arrangement fees
3.0
1.9
Other interest expense
\u2013
2.0
Unwinding of discount on decommissioning provisions
19
11.4
10.1
Total finance costs
345.6
329.6
Interest income on amounts due from Joint Venture Partners for leases
18
(48.1)
(30.1)
Other finance income
(23.4)
(13.9)
Total finance income
(71.5)
(44.0)
Net financing costs
274.1
285.6
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-382": { "value": "
Note 6. Taxation on profit on continuing activities
2024 2023
Notes $m $m
Current tax on profits for the year
UK corporation tax
\u2013
(1.9)
Foreign tax
307.6
322.2
Taxes paid in kind under Production Sharing Contracts
6.3
11.0
Adjustments in respect of prior periods
(3.5)
10.8
Total corporate tax
310.4
342.1
UK petroleum revenue tax
(2.4)
(0.7)
Total current tax
308.0
341.4
Deferred tax
Origination and reversal of temporary differences
UK corporation tax
(19.1)
(22.9)
Foreign tax
(27.0)
(106.5)
Adjustments in respect of prior periods
1.1
(2.8)
Total deferred corporate tax
(45.0)
(132.2)
Deferred UK petroleum revenue tax
3.9
(3.7)
Total deferred tax
20
(41.1)
(135.9)
Total income tax expense
266.9
205.5
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 25% (2023: 23.5%). 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
25% is as follows:
2024 2023
$m $m
Profit from continuing activities before tax
321.5
95.9
Tax on profit from continuing activities at the standard UK corporation tax rate of 25% (2023: 23.5%)
80.4
22.5
Effects of:
Non-deductible exploration expenditure
a
50.3
3.4
Other non-deductible expenses
b
0.4
35.4
Net deferred tax asset not recognised
c
78.2
65.1
Utilisation of tax losses not previously recognised
(0.6)
(0.2)
Adjustment relating to prior years
d
(2.4)
(2.8)
Other tax rates applicable outside the UK
95.9
82.4
Other income not subject to corporation tax
0.3
(0.3)
Tax impact of acquisitions and disposals
(35.6)
\u2013
Total income tax expense for the year
266.9
205.5
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 $4,005.8 million (2023: $4,195.3 million) of which $2,757.8 million are available for offset
indefinitely and $1,248.0 million in the next five to seven 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 $4,005.8 million (2023: $4,165.7
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 $nil (2023: $7.4 million) in relation to tax losses. The Group has suffered
these losses in either the current or preceding period in the tax jurisdiction to which the deferred tax asset relates.
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 2024, nil tax expense (2023: nil tax expense) has been recognised through other comprehensive income.
Global minimum top-up tax
The Group has applied the exception to recognising and disclosing information about deferred tax assets and liabilities
relating to Pillar II income taxes. The Group\u2019s effective tax rate is more than 15% for this period and the Group is not
expecting profit to be taxed at less than 15%.
Note 20. Deferred taxation
Other Deferred
Accelerated tax Tax temporary petroleum
depreciation Decommissioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
0.2
0.2
At 1 January 2024
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
Credit/(charge) to income statement
41.5
(1.5)
(7.4)
26.2
(13.8)
(3.9)
41.1
Acquisitions
1
(44.9)
\u2013
\u2013
\u2013
\u2013
\u2013
(44.9)
At 31 December 2024
(443.6)
66.1
\u2013
(31.9)
2.0
2.7
(404.7)
1. This relates to an acquisition through business combination discussed in note 14.
2024 2023
$m $m
Deferred tax liabilities
(413.0)
(420.5)
Deferred tax assets
8.3
19.6
(404.7)
(400.9)
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-383": { "value": "
Note 7. Earnings/ (loss) per ordinary share
Basic earnings/ (loss) per ordinary share amounts are calculated by dividing net profit/(loss) for the year attributable to
ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year.
Diluted earnings per ordinary share amounts are calculated by dividing net profit/(loss) for the year attributable to
ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year
plus the weighted average number of dilutive ordinary shares that would be issued if employee and other share options
were converted into ordinary shares.
2024 2023
$m $m
Profit/(loss) for the year
Net profit/(loss) attributable to equity shareholders
54.6
(109.6)
Effect of dilutive potential ordinary shares
\u2013
\u2013
Diluted net earnings/(loss) attributable to equity shareholders
54.6
(109.6)
2024 2023
Number Number
Number of shares
Basic weighted average number of shares
1,457,066,889
1,447,121,945
Dilutive potential ordinary shares
77,518,716
\u2013
Diluted weighted average number of shares
1,534,585,605
1,447,121,945
", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-384": { "value": "
Note 8. Intangible exploration and evaluation assets
2024 2023
$m $m
At 1 January
287.0
288.6
Additions
34.7
25.4
Amounts written off
(212.6)
(27.0)
At 31 December
109.1
287.0
The table below provides a summary of the exploration costs written off on a pre-tax basis by country.
2024
Remaining
Rationale for 2024 recoverable
2024 Write-off amount
Country
CGU
write-off $m $m
Argentina
MLO114, MLO119 and MLO122
a
38.8
\u2013
C\u00f4te d\u2019Ivoire
Block 524 and Block 803
a
15.5
\u2013
Gabon
Simba
b
10.3
\u2013
Kenya
Blocks 10BB and 13T
c
145.4
103.2
New Ventures
Various
d
1.3
\u2013
Uganda
Exploration areas 1, 1A, 2 and 3A
e
0.8
\u2013
Other
Various
0.5
\u2013
Total write-off
212.6
a. No further activity planned following unsuccessful farm-down efforts.
b. Uncommercial well costs written off.
c. Delay in farm-down and extension of Field Development Plan review period.
d. New Ventures expenditure is written off as incurred.
e. Indirect tax movement on previously disposed or written off assets.
Kenya Discussions with the Government of Kenya (GoK) on 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 was extended to 30 June 2025. The review of the FDP by EPRA is progressing, and Tullow is in discussions to respond to commercial and technical queries raised as part of the review. The Group expects a production licence to be granted once the reviews are 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 withdrawal will be considered completed and Tullow will have full assignment of 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, which is the only remaining Joint Venture Partner. In the Tullow 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 JOA, it is considered that the ownership of the 50% held by AOC and TE was irrevocably passed to Tullow on 30 June 2023. From that date, Tullow has the right to benefit from the PI and will also be liable for all costs incurred going forward (except those for which the withdrawing parties remain liable for). Tullow has also obtained external legal opinion, which substantiates the above position, however, subject to customary conditions of Tullow having the financial and technical capacity as required under the Petroleum Act. Tullow has submitted an application to the GoK to obtain its approval to execute the transfer of the 50% interest and is still in discussions with EPRA/GoK to address certain commercial and technical points raised in 2H 2024 as part of the approval process. To achieve a Final Investment Decision (FID), securing a strategic partner who will bring requisite commercial and technical abilities is a key milestone. Considering the delay in securing a farm-down offer and the time taken to secure GoK approvals for transfer of the additional 50% interest, an impairment trigger was identified for 31 December 2024 reporting. In line with the accounting policy, recoverable value was determined using a discount cash flow model. The long-term oil price assumptions remain consistent with those used at the end of 2023, while the discount rate has increased by 1%. The cash flows were discounted using a pre-tax nominal discount rate of 21% (2023: 20%). This resulted in a net present value (NPV) significantly more than the carrying value of $248.6 million. However, the Group has identified the following uncertainties in respect of its ability to realise the NPV: receiving and subsequently finalising an acceptable offer from a strategic partner thus enabling FDP approval; obtaining financing for the project; and government deliverables in the form of the provision of required infrastructure and fiscal terms. These items require satisfactory resolution before the Group can take an 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 unrisked NPV to determine a risk-adjusted recoverable value, which was then compared against the net book value of the asset. Certain risks have increased since 31 December 2023, predominantly around achieving a farm-down and receiving government approval for the FDP and the transfer of the additional 50% PI. Tullow continues to receive expressions of interest and non-binding offers from potential strategic partners and is in active discussions with multiple interested parties. Hence the recoverable amount based on risked NPV has been revised to $103.2 million and a further impairment of $145.4 million has been recognised in the year ended 31 December 2024. Management has compared the remaining net book value of the Kenya project with the recoverable value under alternative development options, in case the farm-down based on the FDP is unsuccessful. The alternative development options support the recognition of the remaining net book value of the Kenya project and will be pursued if the current project development plan could not be progressed further. Should the uncertainties around the project be resolved, there will be a reversal from the previously recorded impairment charges of up to $1,075.2 million. However, in the case that an FID decision is not reached, there could be potential changes in the carrying value in the next financial year due to changes in facts and circumstances that influence the risk factors and thus the overall probability weighting, which drives the recoverable value. This can lead to the recognition of additional impairment of up to $103.2 million. The sensitivity disclosure focuses on the binary nature of these uncertainties leading to FID, this being the most relevant sensitivity disclosure, i.e., failure to achieve any one of the factors will result in failure to achieve FID, which will result in the full impairment of the remaining carrying amount. 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 $18.5 million, whilst increases to oil prices specified above would result in a reduction in the impairment charge of $18.4 million. A 1% change in the pre-tax discount rate would result in an additional impairment charge of $15.4 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. Applying the impact of Net Zero emissions by 2050 to the current risking will result in an additional impairment charge of $103.2 million. For Net Zero emissions sensitivities, refer to pages 47 and 48 of the TCFD.
2023
Rationale for 2023 Remaining
2023 Write-off/ recoverable
write-off/ (back) amount
Country
CGU
(back) $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
Simba
f
3.4
\u2013
Other
Various
0.2
\u2013
Total write-off
27.0
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", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-454": { "value": "Note 8. Intangible exploration and evaluation assets
2024 2023
$m $m
At 1 January
287.0
288.6
Additions
34.7
25.4
Amounts written off
(212.6)
(27.0)
At 31 December
109.1
287.0
The table below provides a summary of the exploration costs written off on a pre-tax basis by country.
2024
Remaining
Rationale for 2024 recoverable
2024 Write-off amount
Country
CGU
write-off $m $m
Argentina
MLO114, MLO119 and MLO122
a
38.8
\u2013
C\u00f4te d\u2019Ivoire
Block 524 and Block 803
a
15.5
\u2013
Gabon
Simba
b
10.3
\u2013
Kenya
Blocks 10BB and 13T
c
145.4
103.2
New Ventures
Various
d
1.3
\u2013
Uganda
Exploration areas 1, 1A, 2 and 3A
e
0.8
\u2013
Other
Various
0.5
\u2013
Total write-off
212.6
a. No further activity planned following unsuccessful farm-down efforts. b. Uncommercial well costs written off. c. Delay in farm-down and extension of Field Development Plan review period. d. New Ventures expenditure is written off as incurred. e. Indirect tax movement on previously disposed or written off assets. Kenya Discussions with the Government of Kenya (GoK) on 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 was extended to 30 June 2025. The review of the FDP by EPRA is progressing, and Tullow is in discussions to respond to commercial and technical queries raised as part of the review. The Group expects a production licence to be granted once the reviews are 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 withdrawal will be considered completed and Tullow will have full assignment of 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, which is the only remaining Joint Venture Partner. In the Tullow 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 JOA, it is considered that the ownership of the 50% held by AOC and TE was irrevocably passed to Tullow on 30 June 2023. From that date, Tullow has the right to benefit from the PI and will also be liable for all costs incurred going forward (except those for which the withdrawing parties remain liable for). Tullow has also obtained external legal opinion, which substantiates the above position, however, subject to customary conditions of Tullow having the financial and technical capacity as required under the Petroleum Act. Tullow has submitted an application to the GoK to obtain its approval to execute the transfer of the 50% interest and is still in discussions with EPRA/GoK to address certain commercial and technical points raised in 2H 2024 as part of the approval process. To achieve a Final Investment Decision (FID), securing a strategic partner who will bring requisite commercial and technical abilities is a key milestone. Considering the delay in securing a farm-down offer and the time taken to secure GoK approvals for transfer of the additional 50% interest, an impairment trigger was identified for 31 December 2024 reporting. In line with the accounting policy, recoverable value was determined using a discount cash flow model. The long-term oil price assumptions remain consistent with those used at the end of 2023, while the discount rate has increased by 1%. The cash flows were discounted using a pre-tax nominal discount rate of 21% (2023: 20%). This resulted in a net present value (NPV) significantly more than the carrying value of $248.6 million. However, the Group has identified the following uncertainties in respect of its ability to realise the NPV: receiving and subsequently finalising an acceptable offer from a strategic partner thus enabling FDP approval; obtaining financing for the project; and government deliverables in the form of the provision of required infrastructure and fiscal terms. These items require satisfactory resolution before the Group can take an 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 unrisked NPV to determine a risk-adjusted recoverable value, which was then compared against the net book value of the asset. Certain risks have increased since 31 December 2023, predominantly around achieving a farm-down and receiving government approval for the FDP and the transfer of the additional 50% PI. Tullow continues to receive expressions of interest and non-binding offers from potential strategic partners and is in active discussions with multiple interested parties. Hence the recoverable amount based on risked NPV has been revised to $103.2 million and a further impairment of $145.4 million has been recognised in the year ended 31 December 2024. Management has compared the remaining net book value of the Kenya project with the recoverable value under alternative development options, in case the farm-down based on the FDP is unsuccessful. The alternative development options support the recognition of the remaining net book value of the Kenya project and will be pursued if the current project development plan could not be progressed further. Should the uncertainties around the project be resolved, there will be a reversal from the previously recorded impairment charges of up to $1,075.2 million. However, in the case that an FID decision is not reached, there could be potential changes in the carrying value in the next financial year due to changes in facts and circumstances that influence the risk factors and thus the overall probability weighting, which drives the recoverable value. This can lead to the recognition of additional impairment of up to $103.2 million. The sensitivity disclosure focuses on the binary nature of these uncertainties leading to FID, this being the most relevant sensitivity disclosure, i.e., failure to achieve any one of the factors will result in failure to achieve FID, which will result in the full impairment of the remaining carrying amount. 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 $18.5 million, whilst increases to oil prices specified above would result in a reduction in the impairment charge of $18.4 million. A 1% change in the pre-tax discount rate would result in an additional impairment charge of $15.4 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. Applying the impact of Net Zero emissions by 2050 to the current risking will result in an additional impairment charge of $103.2 million. For Net Zero emissions sensitivities, refer to pages 47 and 48 of the TCFD.
2023
Rationale for 2023 Remaining
2023 Write-off/ recoverable
write-off/ (back) amount
Country
CGU
(back) $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
Simba
f
3.4
\u2013
Other
Various
0.2
\u2013
Total write-off
27.0
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.", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-427": { "value": "Note 8. Intangible exploration and evaluation assets
2024 2023
$m $m
At 1 January
287.0
288.6
Additions
34.7
25.4
Amounts written off
(212.6)
(27.0)
At 31 December
109.1
287.0
The table below provides a summary of the exploration costs written off on a pre-tax basis by country.
2024
Remaining
Rationale for 2024 recoverable
2024 Write-off amount
Country
CGU
write-off $m $m
Argentina
MLO114, MLO119 and MLO122
a
38.8
\u2013
C\u00f4te d\u2019Ivoire
Block 524 and Block 803
a
15.5
\u2013
Gabon
Simba
b
10.3
\u2013
Kenya
Blocks 10BB and 13T
c
145.4
103.2
New Ventures
Various
d
1.3
\u2013
Uganda
Exploration areas 1, 1A, 2 and 3A
e
0.8
\u2013
Other
Various
0.5
\u2013
Total write-off
212.6
a. No further activity planned following unsuccessful farm-down efforts. b. Uncommercial well costs written off. c. Delay in farm-down and extension of Field Development Plan review period. d. New Ventures expenditure is written off as incurred. e. Indirect tax movement on previously disposed or written off assets.
Kenya
Discussions with the Government of Kenya (GoK) on 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 was extended to 30 June 2025.
The review of the FDP by EPRA is progressing, and Tullow is in discussions to respond to commercial and technical queries
raised as part of the review. The Group expects a production licence to be granted once the reviews are 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 withdrawal will be considered completed and Tullow will have full assignment of 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, which is the only remaining Joint Venture Partner.
In the Tullow 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 JOA, it is considered that the ownership of the 50% held by AOC and TE was
irrevocably passed to Tullow on 30 June 2023. From that date, Tullow has the right to benefit from the PI and will also be
liable for all costs incurred going forward (except those for which the withdrawing parties remain liable for). Tullow has
also obtained external legal opinion, which substantiates the above position, however, subject to customary conditions
of Tullow having the financial and technical capacity as required under the Petroleum Act. Tullow has submitted an
application to the GoK to obtain its approval to execute the transfer of the 50% interest and is still in discussions
with EPRA/GoK to address certain commercial and technical points raised in 2H 2024 as part of the approval process.
To achieve a Final Investment Decision (FID), securing a strategic partner who will bring requisite commercial and technical
abilities is a key milestone. Considering the delay in securing a farm-down offer and the time taken to secure GoK approvals
for transfer of the additional 50% interest, an impairment trigger was identified for 31 December 2024 reporting.
In line with the accounting policy, recoverable value was determined using a discount cash flow model. The long-term oil
price assumptions remain consistent with those used at the end of 2023, while the discount rate has increased by 1%. The
cash flows were discounted using a pre-tax nominal discount rate of 21% (2023: 20%). This resulted in a net present value
(NPV) significantly more than the carrying value of $248.6 million. However, the Group has identified the following
uncertainties in respect of its ability to realise the NPV: receiving and subsequently finalising an acceptable offer from a
strategic partner thus enabling FDP approval; obtaining financing for the project; and government deliverables in the
form of the provision of required infrastructure and fiscal terms. These items require satisfactory resolution before the
Group can take an 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 unrisked NPV to determine a risk-adjusted
recoverable value, which was then compared against the net book value of the asset. Certain risks have increased since
31 December 2023, predominantly around achieving a farm-down and receiving government approval for the FDP and
the transfer of the additional 50% PI. Tullow continues to receive expressions of interest and non-binding offers from
potential strategic partners and is in active discussions with multiple interested parties. Hence the recoverable amount
based on risked NPV has been revised to $103.2 million and a further impairment of $145.4 million has been recognised
in the year ended 31 December 2024.
Management has compared the remaining net book value of the Kenya project with the recoverable value under
alternative development options, in case the farm-down based on the FDP is unsuccessful. The alternative development
options support the recognition of the remaining net book value of the Kenya project and will be pursued if the current
project development plan could not be progressed further.
Should the uncertainties around the project be resolved, there will be a reversal from the previously recorded impairment
charges of up to $1,075.2 million. However, in the case that an FID decision is not reached, there could be potential
changes in the carrying value in the next financial year due to changes in facts and circumstances that influence the risk
factors and thus the overall probability weighting, which drives the recoverable value. This can lead to the recognition of
additional impairment of up to $103.2 million. The sensitivity disclosure focuses on the binary nature of these
uncertainties leading to FID, this being the most relevant sensitivity disclosure, i.e., failure to achieve any one of the
factors will result in failure to achieve FID, which will result in the full impairment of the remaining carrying amount.
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 $18.5
million, whilst increases to oil prices specified above would result in a reduction in the impairment charge of $18.4 million.
A 1% change in the pre-tax discount rate would result in an additional impairment charge of $15.4 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.
Applying the impact of Net Zero emissions by 2050 to the current risking will result in an additional impairment charge
of $103.2 million.
For Net Zero emissions sensitivities, refer to pages 47 and 48 of the TCFD.
2023
Rationale for 2023 Remaining
2023 Write-off/ recoverable
write-off/ (back) amount
Country
CGU
(back) $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
Simba
f
3.4
\u2013
Other
Various
0.2
\u2013
Total write-off
27.0
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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-385": { "value": "
Note 9. Property, plant and equipment
2024 2024 2024 2023 2023 2023
Oil Other Right Oil Other Right
and gas fixed of use 2024 and gas fixed of use 2023
assets assets assets Total assets assets assets Total
Notes $m $m $m $m $m $m $m $m
Cost
At 1 January
11,282.1
21.9
1,268.8
12,572.8
11,182.6
30.0
1,196.8
12,409.4
Additions
1
1
151.6
3.1
1.4
156.1
416.1
2.3
81.1
499.5
Acquisitions
2
1
97.4
\u2013
\u2013
97.4
\u2013
\u2013
\u2013
\u2013
Transfer to assets held for sale
\u2013
\u2013
\u2013
\u2013
(302.8)
\u2013
\u2013
(302.8)
Asset retirement
3
\u2013
(1.3)
(145.3)
(146.6)
(67.7)
(11.0)
(10.6)
(89.3)
Currency translation
adjustments
(17.3)
(0.3)
(0.5)
(18.1)
53.9
0.6
1.5
56.0
At 31 December
11,513.8
23.4
1,124.4
12,661.6
11,282.1
21.9
1,268.8
12,572.8
Depreciation, depletion,
amortisation and impairment
At 1 January
(9,377.7)
(17.5)
(644.8)
(10,040.0)
(8,888.4)
(24.4)
(515.2)
(9,428.0)
Charge for the year
4
(350.3)
(2.5)
(91.4)
(444.2)
(351.6)
(3.6)
(81.4)
(436.6)
Impairment reversal/(loss)
11.8
\u2013
\u2013
11.8
(399.1)
\u2013
(9.0)
(408.1)
Capitalised depreciation
\u2013
\u2013
(29.5)
(29.5)
\u2013
\u2013
(49.3)
(49.3)
Transfer to assets held for sale
\u2013
\u2013
\u2013
\u2013
247.6
\u2013
\u2013
247.6
Asset retirement
3
\u2013
1.3
145.3
146.6
67.7
11.0
10.6
89.3
Currency translation
adjustments
17.3
0.1
0.4
17.8
(53.9)
(0.5)
(0.5)
(54.9)
At 31 December
(9,698.9)
(18.6)
(620.0)
(10,337.5)
(9,377.7)
(17.5)
(644.8)
(10,040.0)
Net book value at 31 December
1,814.9
4.8
504.4
2,324.1
1,904.4
4.4
624.0
2,532.8
1.
Included in additions is an impairment reversal of $19.7 million (2023: impairment loss of $27.9 million) in respect of decommissioning costs in
Mauritania.
2. This relates to the Gabon asset swap transaction discussed in note 14 Business combination.
3. The asset retirement of right-of-use assets in 2024 relates to the disposal of a drilling ship following completion of the 2023 drilling programme.
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 2024 and 2023, 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
2024
$74/bbl
$71/bbl
$75/bbl
$75/bbl
$75/bbl
$75/bbl inflated at 2%
2023
$78/bbl
$75/bbl
$75/bbl
$75/bbl
$75/bbl
$75/bbl inflated at 2%
2024
Trigger for 2024 Remaining
2024 Impairment/ Pre-tax recoverable
impairment/ (reversal) discount rate
amount
e
(reversal) $m assumption $m
Espoir (C\u00f4te d\u2019Ivoire)
a
2.5
14%
\u2013
Mauritania
b
(19.7)
n/a
\u2013
UK CGU
c,d
5.4
n/a
\u2013
Impairment reversal
(11.8)
\u2013
a. Change to decommissioning discount rate.
b. Impairment reversal driven by operational efficiencies and scope revision.
c. Change to decommissioning estimate.
d. The fields in the UK are grouped into one CGU as all fields share critical gas infrastructure.
e. The remaining recoverable amount of the asset is its value in use.
The impairment reversal identified in Mauritania was driven by revisions to the scope of decommissioning activities
undertaken as well as operational efficiencies implemented following the transition to directly operating the campaign.
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.
For Net Zero emissions sensitivities, refer to pages 47 and 48 of the TCFD and note 25 Climate change and energy transition.
2023
Pre-tax Remaining
Trigger for 2023 discount recoverable
2023 Impairment 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 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.
", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-386": { "value": "
Note 10. Other assets
2024 2023
$m $m
Non-current
Amounts due from Joint Venture Partners
333.1
332.5
VAT recoverable
7.7
6.1
340.8
338.6
Current
Amounts due from Joint Venture Partners
350.2
498.1
Underlifts
20.9
47.8
Prepayments
17.1
21.1
Other current assets
3.7
4.2
391.9
571.2
732.7
909.8
Non-current receivables from JV Partners include the Ghana decommissioning fund, which relates to the requirement
for JV Partners of the Unitisation and Unit Operating Agreement (UUOA) to establish a trust fund in which the estimated
cost of decommissioning and abandonment are accrued to cover decommissioning obligations in respect of the Jubilee
Field Unit when the trigger date occurs. As at 31 December 2024, Tullow has contributed $11.6 million (2023: $nil) into the
decommissioning trust fund.
The decrease in current receivables from JV Partners compared to 31 December 2023 mainly relates to partners\u2019 share
of decreased accrual balances (note 15), net decrease in GNPC (Ghana National Petroleum Corporation) receivable,
lower balance of current receivables relating to leases (note 18) and other working capital movements.
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-475": { "value": "Note 10. Other assets
2024 2023
$m $m
Non-current
Amounts due from Joint Venture Partners
333.1
332.5
VAT recoverable
7.7
6.1
340.8
338.6
Current
Amounts due from Joint Venture Partners
350.2
498.1
Underlifts
20.9
47.8
Prepayments
17.1
21.1
Other current assets
3.7
4.2
391.9
571.2
732.7
909.8
Non-current receivables from JV Partners include the Ghana decommissioning fund, which relates to the requirement for JV Partners of the Unitisation and Unit Operating Agreement (UUOA) to establish a trust fund in which the estimated cost of decommissioning and abandonment are accrued to cover decommissioning obligations in respect of the Jubilee Field Unit when the trigger date occurs. As at 31 December 2024, Tullow has contributed $11.6 million (2023: $nil) into the decommissioning trust fund. The decrease in current receivables from JV Partners compared to 31 December 2023 mainly relates to partners\u2019 share of decreased accrual balances (note 15), net decrease in GNPC (Ghana National Petroleum Corporation) receivable, lower balance of current receivables relating to leases (note 18) and other working capital movements. 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 2024 of $137.9 million (2023: $43.5 million) mainly relates to gross gas receivable in Ghana of $124.4 million (Tullow net share of gas receivable: $56.2 million). Expected credit loss charge on trade receivables As at 31 December 2024, the allowance for expected credit losses (ECL) stood at $6.6 million (2023: $nil) on the net gas receivable balance in Ghana of $56.2 million. The amounts provided in 2024 reflect the increase in the net gas balance receivable from 31 December 2023 due to delays in payments received during the year and changes in external credit ratings. No allowance for ECL has been provided on balances receivable where mitigating contract clauses ensure that amounts due will be fully recovered. Note 20. Deferred taxation
Other Deferred
Accelerated tax Tax temporary petroleum
depreciation Decommissioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
0.2
0.2
At 1 January 2024
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
Credit/(charge) to income statement
41.5
(1.5)
(7.4)
26.2
(13.8)
(3.9)
41.1
Acquisitions
1
(44.9)
\u2013
\u2013
\u2013
\u2013
\u2013
(44.9)
At 31 December 2024
(443.6)
66.1
\u2013
(31.9)
2.0
2.7
(404.7)
1. This relates to an acquisition through business combination discussed in note 14.
2024 2023
$m $m
Deferred tax liabilities
(413.0)
(420.5)
Deferred tax assets
8.3
19.6
(404.7)
(400.9)
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-455": { "value": "Note 10. Other assets
2024 2023
$m $m
Non-current
Amounts due from Joint Venture Partners
333.1
332.5
VAT recoverable
7.7
6.1
340.8
338.6
Current
Amounts due from Joint Venture Partners
350.2
498.1
Underlifts
20.9
47.8
Prepayments
17.1
21.1
Other current assets
3.7
4.2
391.9
571.2
732.7
909.8
Non-current receivables from JV Partners include the Ghana decommissioning fund, which relates to the requirement for JV Partners of the Unitisation and Unit Operating Agreement (UUOA) to establish a trust fund in which the estimated cost of decommissioning and abandonment are accrued to cover decommissioning obligations in respect of the Jubilee Field Unit when the trigger date occurs. As at 31 December 2024, Tullow has contributed $11.6 million (2023: $nil) into the decommissioning trust fund. The decrease in current receivables from JV Partners compared to 31 December 2023 mainly relates to partners\u2019 share of decreased accrual balances (note 15), net decrease in GNPC (Ghana National Petroleum Corporation) receivable, lower balance of current receivables relating to leases (note 18) and other working capital movements. ", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-428": { "value": "Note 10. Other assets
2024 2023
$m $m
Non-current
Amounts due from Joint Venture Partners
333.1
332.5
VAT recoverable
7.7
6.1
340.8
338.6
Current
Amounts due from Joint Venture Partners
350.2
498.1
Underlifts
20.9
47.8
Prepayments
17.1
21.1
Other current assets
3.7
4.2
391.9
571.2
732.7
909.8
Non-current receivables from JV Partners include the Ghana decommissioning fund, which relates to the requirement for JV Partners of the Unitisation and Unit Operating Agreement (UUOA) to establish a trust fund in which the estimated cost of decommissioning and abandonment are accrued to cover decommissioning obligations in respect of the Jubilee Field Unit when the trigger date occurs. As at 31 December 2024, Tullow has contributed $11.6 million (2023: $nil) into the decommissioning trust fund. The decrease in current receivables from JV Partners compared to 31 December 2023 mainly relates to partners\u2019 share of decreased accrual balances (note 15), net decrease in GNPC (Ghana National Petroleum Corporation) receivable, lower balance of current receivables relating to leases (note 18) and other working capital movements. ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-387": { "value": "
Note 11. Inventories
2024 2023
$m $m
Warehouse stock and materials
78.2
71.5
Oil stock
54.2
35.8
132.4
107.3
The increase in oil stock from 31 December 2023 is mainly driven by increase in Ghana of $16.6 million due to timing
of liftings.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-388": { "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 2024 of $137.9 million (2023: $43.5 million) mainly relates to gross
gas receivable in Ghana of $124.4 million (Tullow net share of gas receivable: $56.2 million).
Expected credit loss charge on trade receivables
As at 31 December 2024, the allowance for expected credit losses (ECL) stood at $6.6 million (2023: $nil) on the net gas
receivable balance in Ghana of $56.2 million. The amounts provided in 2024 reflect the increase in the net gas balance
receivable from 31 December 2023 due to delays in payments received during the year and changes in external credit
ratings. No allowance for ECL has been provided on balances receivable where mitigating contract clauses ensure that
amounts due will be fully recovered.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-389": { "value": "
Note 13. Cash and cash equivalents
2024 2023
$m $m
Cash at bank
151.2
114.9
Money market funds and other cash equivalents
403.9
384.1
555.1
499.0
Cash and cash equivalents include an amount of $83.5 million (2023: $36.9 million) which the Group holds as operator
in Joint Venture bank accounts. Included in cash at bank is $6.5 million (2023: $4.5 million) held as security for
performance bonds relating to work commitments on exploration licences.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashAndCashEquivalentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-390": { "value": "
Note 14. Business combination
On 29 February 2024, the Group completed the asset swap agreement (ASA) transaction with Perenco Oil and Gas
Gabon S.A (Perenco). The rationale for the transaction is the simplification of the Group\u2019s equity ownership across key
fields in Gabon, creating better alignment between the participating interest partners and streamlining processes such
as budgeting, cost management and capital allocation. The revised portfolio of assets will enable Tullow to leverage
its technical skills and focus on more material positions in key fields.
The transaction is an asset swap achieved through the exchange of participating interests held by both parties in certain
licences in Gabon. The exchange represents the acquisition of an additional interest in a joint operation that constitutes
a business, and therefore IFRS 11 Joint Arrangements requires the application of the principles in IFRS 3 Business Combinations.
In line with the requirements of IFRS 3, the interests transferred as part of the consideration, which comprises mainly of
property, plant, and equipment of $54.4 million, have been remeasured to the acquisition date fair value of $93.3 million.
This has resulted in an asset revaluation gain of $38.9 million recognised in the income statement at 31 December 2024.
The table below shows the pre-completion and post-completion equities in the licences subject to the transaction:
Field
Pre-completion
Post-completion
Kowe (Tchatamba)
Acquisition
25.0%
40.0%
DE8
Acquisition
20.0%
40.0%
Simba
Disposal
57.5%
40.0%
Limande
Disposal
40.0%
0%
Turnix
Disposal
27.5%
0%
Moba
Disposal
24.3%
0%
Oba
Disposal
10.0%
0%
The exchange of the transferred interests between the parties was deemed for all purposes to be made with effect from
the economic date of 1 February 2023, but completed on 29 February 2024 and this is therefore the acquisition date.
The transaction was intended to be cash neutral on the economic date as the fair value of the assets exchanged were
considered to be equal at that time, and therefore no additional consideration would have been payable by either party
at that time. However, as the transaction completed more than a year later, the ASA included provisions to ensure the
neutrality of the transaction via cash adjustments for the period between the economic date and the completion date,
the agreed adjustment upon completion was $8.1 million, which has been included in investing activities in the cash flow
statement.
The fair values of the identifiable assets and liabilities acquired were:
Fair value
recognised on
acquisition
$m
Intangible assets
1.0
Property, plant and equipment
97.4
Other current assets
0.7
Goodwill
44.9
Total assets acquired
144.0
Provisions
(5.8)
Deferred tax liabilities
(44.9)
Total liabilities assumed
(50.7)
Net identifiable assets acquired
93.3
Total purchase consideration
(93.3)
Consideration satisfied by exchange of assets
(85.2)
Consideration satisfied by cash
(8.1)
Purchase of additional interest in joint operation per the cash flow statement
(8.1)
The disclosure requirement of IFRS 3 in relation to contributions to revenue and profit or loss have not been included
as they are impracticable to obtain due to Tullow not being the operator of the assets.
No material acquisition-related costs were incurred in relation to the transaction.
Valuation methodology and assumptions
The fair value of the purchase consideration of $93.3 million reflects the discounted future cash flows of the assets
and liabilities exchanged as part of the swap as the transaction is intended to be value neutral. Provisions represent
the present value of decommissioning costs which are expected to be incurred after the end of the licence in 2046.
Goodwill
Goodwill of $44.9 million was recognised from the asset swap. IAS 12 Income Taxes requires recognition of a deferred
tax asset or liability for the difference between the fair value of the assets acquired and liabilities assumed, and their
respective tax bases. Therefore, goodwill has arisen as a direct result of the recognition of the deferred tax liability.
None of the goodwill is deductible for income tax purposes.
The goodwill acquired through the business combination is allocated fully to the Tchatamba cash-generating unit (CGU),
for the purposes of impairment testing. Refer to note 9 for full disclosure of the outcome of the impairment test at
31 December 2024. Significant headroom remained between the net present value (NPV) and the book value of the
CGU and management did not identify an impairment for this CGU .
Asset held for sale
As at 31 December 2024, the Group had no assets classified as held for sale (2023: $55.8 million) and no liabilities
associated with assets classified as held for sale (2023: $17.6 million). The previously classified AHFS, relating to the
Gabon asset swap, was derecognised when the transaction was completed during the year as disclosed above.
", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsHeldForSaleAndDiscontinuedOperationsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-429": { "value": "Note 14. Business combination On 29 February 2024, the Group completed the asset swap agreement (ASA) transaction with Perenco Oil and Gas Gabon S.A (Perenco). The rationale for the transaction is the simplification of the Group\u2019s equity ownership across key fields in Gabon, creating better alignment between the participating interest partners and streamlining processes such as budgeting, cost management and capital allocation. The revised portfolio of assets will enable Tullow to leverage its technical skills and focus on more material positions in key fields. The transaction is an asset swap achieved through the exchange of participating interests held by both parties in certain licences in Gabon. The exchange represents the acquisition of an additional interest in a joint operation that constitutes a business, and therefore IFRS 11 Joint Arrangements requires the application of the principles in IFRS 3 Business Combinations. In line with the requirements of IFRS 3, the interests transferred as part of the consideration, which comprises mainly of property, plant, and equipment of $54.4 million, have been remeasured to the acquisition date fair value of $93.3 million. This has resulted in an asset revaluation gain of $38.9 million recognised in the income statement at 31 December 2024. The table below shows the pre-completion and post-completion equities in the licences subject to the transaction:
Field
Pre-completion
Post-completion
Kowe (Tchatamba)
Acquisition
25.0%
40.0%
DE8
Acquisition
20.0%
40.0%
Simba
Disposal
57.5%
40.0%
Limande
Disposal
40.0%
0%
Turnix
Disposal
27.5%
0%
Moba
Disposal
24.3%
0%
Oba
Disposal
10.0%
0%
The exchange of the transferred interests between the parties was deemed for all purposes to be made with effect from the economic date of 1 February 2023, but completed on 29 February 2024 and this is therefore the acquisition date. The transaction was intended to be cash neutral on the economic date as the fair value of the assets exchanged were considered to be equal at that time, and therefore no additional consideration would have been payable by either party at that time. However, as the transaction completed more than a year later, the ASA included provisions to ensure the neutrality of the transaction via cash adjustments for the period between the economic date and the completion date, the agreed adjustment upon completion was $8.1 million, which has been included in investing activities in the cash flow statement. The fair values of the identifiable assets and liabilities acquired were:
Fair value
recognised on
acquisition
$m
Intangible assets
1.0
Property, plant and equipment
97.4
Other current assets
0.7
Goodwill
44.9
Total assets acquired
144.0
Provisions
(5.8)
Deferred tax liabilities
(44.9)
Total liabilities assumed
(50.7)
Net identifiable assets acquired
93.3
Total purchase consideration
(93.3)
Consideration satisfied by exchange of assets
(85.2)
Consideration satisfied by cash
(8.1)
Purchase of additional interest in joint operation per the cash flow statement
(8.1)
The disclosure requirement of IFRS 3 in relation to contributions to revenue and profit or loss have not been included as they are impracticable to obtain due to Tullow not being the operator of the assets. No material acquisition-related costs were incurred in relation to the transaction. Valuation methodology and assumptions The fair value of the purchase consideration of $93.3 million reflects the discounted future cash flows of the assets and liabilities exchanged as part of the swap as the transaction is intended to be value neutral. Provisions represent the present value of decommissioning costs which are expected to be incurred after the end of the licence in 2046. Goodwill Goodwill of $44.9 million was recognised from the asset swap. IAS 12 Income Taxes requires recognition of a deferred tax asset or liability for the difference between the fair value of the assets acquired and liabilities assumed, and their respective tax bases. Therefore, goodwill has arisen as a direct result of the recognition of the deferred tax liability. None of the goodwill is deductible for income tax purposes. The goodwill acquired through the business combination is allocated fully to the Tchatamba cash-generating unit (CGU), for the purposes of impairment testing. Refer to note 9 for full disclosure of the outcome of the impairment test at 31 December 2024. Significant headroom remained between the net present value (NPV) and the book value of the CGU and management did not identify an impairment for this CGU . Asset held for sale As at 31 December 2024, the Group had no assets classified as held for sale (2023: $55.8 million) and no liabilities associated with assets classified as held for sale (2023: $17.6 million). The previously classified AHFS, relating to the Gabon asset swap, was derecognised when the transaction was completed during the year as disclosed above.", "dimensions": { "concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-456": { "value": "Note 14. Business combination On 29 February 2024, the Group completed the asset swap agreement (ASA) transaction with Perenco Oil and Gas Gabon S.A (Perenco). The rationale for the transaction is the simplification of the Group\u2019s equity ownership across key fields in Gabon, creating better alignment between the participating interest partners and streamlining processes such as budgeting, cost management and capital allocation. The revised portfolio of assets will enable Tullow to leverage its technical skills and focus on more material positions in key fields. The transaction is an asset swap achieved through the exchange of participating interests held by both parties in certain licences in Gabon. The exchange represents the acquisition of an additional interest in a joint operation that constitutes a business, and therefore IFRS 11 Joint Arrangements requires the application of the principles in IFRS 3 Business Combinations. In line with the requirements of IFRS 3, the interests transferred as part of the consideration, which comprises mainly of property, plant, and equipment of $54.4 million, have been remeasured to the acquisition date fair value of $93.3 million. This has resulted in an asset revaluation gain of $38.9 million recognised in the income statement at 31 December 2024. The table below shows the pre-completion and post-completion equities in the licences subject to the transaction:
Field
Pre-completion
Post-completion
Kowe (Tchatamba)
Acquisition
25.0%
40.0%
DE8
Acquisition
20.0%
40.0%
Simba
Disposal
57.5%
40.0%
Limande
Disposal
40.0%
0%
Turnix
Disposal
27.5%
0%
Moba
Disposal
24.3%
0%
Oba
Disposal
10.0%
0%
The exchange of the transferred interests between the parties was deemed for all purposes to be made with effect from the economic date of 1 February 2023, but completed on 29 February 2024 and this is therefore the acquisition date. The transaction was intended to be cash neutral on the economic date as the fair value of the assets exchanged were considered to be equal at that time, and therefore no additional consideration would have been payable by either party at that time. However, as the transaction completed more than a year later, the ASA included provisions to ensure the neutrality of the transaction via cash adjustments for the period between the economic date and the completion date, the agreed adjustment upon completion was $8.1 million, which has been included in investing activities in the cash flow statement. The fair values of the identifiable assets and liabilities acquired were:
Fair value
recognised on
acquisition
$m
Intangible assets
1.0
Property, plant and equipment
97.4
Other current assets
0.7
Goodwill
44.9
Total assets acquired
144.0
Provisions
(5.8)
Deferred tax liabilities
(44.9)
Total liabilities assumed
(50.7)
Net identifiable assets acquired
93.3
Total purchase consideration
(93.3)
Consideration satisfied by exchange of assets
(85.2)
Consideration satisfied by cash
(8.1)
Purchase of additional interest in joint operation per the cash flow statement
(8.1)
The disclosure requirement of IFRS 3 in relation to contributions to revenue and profit or loss have not been included as they are impracticable to obtain due to Tullow not being the operator of the assets. No material acquisition-related costs were incurred in relation to the transaction. Valuation methodology and assumptions The fair value of the purchase consideration of $93.3 million reflects the discounted future cash flows of the assets and liabilities exchanged as part of the swap as the transaction is intended to be value neutral. Provisions represent the present value of decommissioning costs which are expected to be incurred after the end of the licence in 2046. Goodwill Goodwill of $44.9 million was recognised from the asset swap. IAS 12 Income Taxes requires recognition of a deferred tax asset or liability for the difference between the fair value of the assets acquired and liabilities assumed, and their respective tax bases. Therefore, goodwill has arisen as a direct result of the recognition of the deferred tax liability. None of the goodwill is deductible for income tax purposes. The goodwill acquired through the business combination is allocated fully to the Tchatamba cash-generating unit (CGU), for the purposes of impairment testing. Refer to note 9 for full disclosure of the outcome of the impairment test at 31 December 2024. Significant headroom remained between the net present value (NPV) and the book value of the CGU and management did not identify an impairment for this CGU Asset held for sale As at 31 December 2024, the Group had no assets classified as held for sale (2023: $55.8 million) and no liabilities associated with assets classified as held for sale (2023: $17.6 million). The previously classified AHFS, relating to the Gabon asset swap, was derecognised when the transaction was completed during the year as disclosed above.", "dimensions": { "concept": "ifrs-full:DisclosureOfNoncurrentAssetsOrDisposalGroupsClassifiedAsHeldForSaleExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-391": { "value": "
Note 15. Trade and other payables
Current liabilities
2024 2023
Notes $m $m
Trade payables
75.7
22.3
Other payables
96.8
65.3
Overlifts
38.3
3.1
Accruals
373.8
498.6
Current portion of lease liabilities
18
151.9
185.7
736.5
775.0
Accruals relate to operating and administrative expenditure of $196.3 million (2023: $209.2 million), capital expenditure of
$119.6 million (2023: $225.6 million), interest expense on bonds of $35.3 million (2023: $40.9 million) and staff-related
expenses of $22.6 million (2023: $22.9 million). The movement in the balance is predominantly driven by a decreased
work programme in Ghana during 2024 compared to 2023.
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) 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 and non-current lease liabilities is mainly driven by the level of drilling activity in Ghana (note 18).
Non-current liabilities
2024 2023
Notes $m $m
Other non-current liabilities
1
84.9
62.2
Non-current portion of lease liabilities
18
581.0
721.0
665.9
783.2
1. Other non-current liabilities include balances related to JV Partners.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-480": { "value": "Note 15. Trade and other payables Current liabilities
2024 2023
Notes $m $m
Trade payables
75.7
22.3
Other payables
96.8
65.3
Overlifts
38.3
3.1
Accruals
373.8
498.6
Current portion of lease liabilities
18
151.9
185.7
736.5
775.0
Accruals relate to operating and administrative expenditure of $196.3 million (2023: $209.2 million), capital expenditure of $119.6 million (2023: $225.6 million), interest expense on bonds of $35.3 million (2023: $40.9 million) and staff-related expenses of $22.6 million (2023: $22.9 million). The movement in the balance is predominantly driven by a decreased work programme in Ghana during 2024 compared to 2023. 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) 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 and non-current lease liabilities is mainly driven by the level of drilling activity in Ghana (note 18). Non-current liabilities
2024 2023
Notes $m $m
Other non-current liabilities
1
84.9
62.2
Non-current portion of lease liabilities
18
581.0
721.0
665.9
783.2
1. Other non-current liabilities include balances related to JV Partners. Note 20. Deferred taxation
Other Deferred
Accelerated tax Tax temporary petroleum
depreciation Decommissioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
0.2
0.2
At 1 January 2024
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
Credit/(charge) to income statement
41.5
(1.5)
(7.4)
26.2
(13.8)
(3.9)
41.1
Acquisitions
1
(44.9)
\u2013
\u2013
\u2013
\u2013
\u2013
(44.9)
At 31 December 2024
(443.6)
66.1
\u2013
(31.9)
2.0
2.7
(404.7)
1. This relates to an acquisition through business combination discussed in note 14.
2024 2023
$m $m
Deferred tax liabilities
(413.0)
(420.5)
Deferred tax assets
8.3
19.6
(404.7)
(400.9)
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-468": { "value": "Note 15. Trade and other payables Current liabilities
2024 2023
Notes $m $m
Trade payables
75.7
22.3
Other payables
96.8
65.3
Overlifts
38.3
3.1
Accruals
373.8
498.6
Current portion of lease liabilities
18
151.9
185.7
736.5
775.0
Accruals relate to operating and administrative expenditure of $196.3 million (2023: $209.2 million), capital expenditure of $119.6 million (2023: $225.6 million), interest expense on bonds of $35.3 million (2023: $40.9 million) and staff-related expenses of $22.6 million (2023: $22.9 million). The movement in the balance is predominantly driven by a decreased work programme in Ghana during 2024 compared to 2023. 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) 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 and non-current lease liabilities is mainly driven by the level of drilling activity in Ghana (note 18). Non-current liabilities
2024 2023
Notes $m $m
Other non-current liabilities
1
84.9
62.2
Non-current portion of lease liabilities
18
581.0
721.0
665.9
783.2
1. Other non-current liabilities include balances related to JV Partners. ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-457": { "value": "Note 15. Trade and other payables Current liabilities
2024 2023
Notes $m $m
Trade payables
75.7
22.3
Other payables
96.8
65.3
Overlifts
38.3
3.1
Accruals
373.8
498.6
Current portion of lease liabilities
18
151.9
185.7
736.5
775.0
Accruals relate to operating and administrative expenditure of $196.3 million (2023: $209.2 million), capital expenditure of $119.6 million (2023: $225.6 million), interest expense on bonds of $35.3 million (2023: $40.9 million) and staff-related expenses of $22.6 million (2023: $22.9 million). The movement in the balance is predominantly driven by a decreased work programme in Ghana during 2024 compared to 2023. 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) 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 and non-current lease liabilities is mainly driven by the level of drilling activity in Ghana (note 18). Non-current liabilities
2024 2023
Notes $m $m
Other non-current liabilities
1
84.9
62.2
Non-current portion of lease liabilities
18
581.0
721.0
665.9
783.2
1. Other non-current liabilities include balances related to JV Partners. ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-430": { "value": "Note 15. Trade and other payables Current liabilities
2024 2023
Notes $m $m
Trade payables
75.7
22.3
Other payables
96.8
65.3
Overlifts
38.3
3.1
Accruals
373.8
498.6
Current portion of lease liabilities
18
151.9
185.7
736.5
775.0
Accruals relate to operating and administrative expenditure of $196.3 million (2023: $209.2 million), capital expenditure of $119.6 million (2023: $225.6 million), interest expense on bonds of $35.3 million (2023: $40.9 million) and staff-related expenses of $22.6 million (2023: $22.9 million). The movement in the balance is predominantly driven by a decreased work programme in Ghana during 2024 compared to 2023. 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) 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 and non-current lease liabilities is mainly driven by the level of drilling activity in Ghana (note 18). Non-current liabilities
2024 2023
Notes $m $m
Other non-current liabilities
1
84.9
62.2
Non-current portion of lease liabilities
18
581.0
721.0
665.9
783.2
1. Other non-current liabilities include balances related to JV Partners. ", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-392": { "value": "
Note 16. Borrowings
2024 2023
$m $m
Current
Borrowings \u2013 within one year
7.00% Senior Notes due 2025
489.4
\u2013
10.25% Senior Secured Notes due 2026
100.0
100.0
589.4
100.0
2024 2023
$m $m
Non-current
Borrowings \u2013 after one year but within five years
7.00% Senior Notes due 2025
\u2013
489.0
10.25% Senior Secured Notes due 2026
1,274.4
1,371.0
Secured Notes Facility due 2028
112.0
124.6
1,386.4
1,984.6
Carrying value of total borrowings
1,975.8
2,084.6
The Group\u2019s capital structure includes $1,385 million Senior Secured Notes due in May 2026 (2026 Notes), $493 million
Senior Notes due in March 2025 (2025 Notes), a $400 million Secured Notes Facility and a $250 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 2024, the Group made a mandatory prepayment of $100 million of the 2026 Notes.
The 2025 Notes are due in a single payment in March 2025.
The Company extended the maturity of its SSRCF from December 2024 to June 2025. The size of the facility also
reduced from $500 million to $250 million to align with lower headroom needs and to continue to reduce financing
costs, with all other terms unchanged. The SSRCF remains undrawn as at 31 December 2024.
Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes, Secured Notes Facility and the SSRCF are
$10.9 million (2023: $14.3 million), $3.1 million (2023: $3.6 million), $17.7 million (2023: $5.0 million) and $nil million
(2023: $2.3 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 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, 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 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 1.1 times 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 refinance, retire or purchase any or all of its
outstanding debt through new debt refinancings and/or cash purchases, in open-market purchases, privately negotiated
transactions or otherwise. Such refinancings or repurchases, if any, will be upon such terms and at such prices as
management may determine, and will depend on prevailing market conditions, liquidity requirements and other factors.
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.
Note 17. Financial instruments
Tullow is permitted to refinance the 2025 Notes with new indebtedness which is unsecured and ranks junior to the
Secured Notes Facility.
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 is monitored and reviewed internally on a regular basis.
The Group does not enter into or trade financial instruments, including derivatives, for speculative purposes.
2024 2023
$m $m
Financial assets
Financial assets at amortised cost
Trade receivables
137.9
43.5
Amounts due from Joint Venture Partners
683.4
830.6
Cash and cash equivalents
555.1
499.0
Derivative financial instruments
Used for hedging
0.1
\u2013
1,376.5
1,373.1
Financial liabilities
Liabilities at amortised cost
Trade payables
160.6
84.5
Other payables
508.9
567.0
Borrowings
1,975.8
2,084.6
Lease liabilities
732.9
906.7
Derivative financial instruments
Used for hedging
11.9
35.0
3,390.1
3,67
7.8
Fair values of financial assets and liabilities
With the exception of the 2026 Notes, the 2025 Notes and the Secured Notes Facility, 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 2024 was $1,188.2 million (2023: $1,327.3 million)
and $418.7 million (2023: $458.3 million) respectively. These are compared to their carrying value of $1,374.4 million
(2023: $1,470.9 million) and $489.5 million (2023: $489.0 million). The fair value of the Secured Notes Facility was
$128.4 million (2023: $130.0 million), estimated by discounting future cash flows by the relevant market rates at the
balance sheet date. The 2026 Notes and the 2025 Notes are categorised as Level 1 in the fair value hierarchy.
Except for expected credit losses as disclosed in note 12, no other 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:
2024 2024 2023 2023
Less than 1\u20133 2024 Less than 1\u20133 2023
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
6.2
\u2013
6.2
(13.3)
\u2013
(13.3)
Deferred premium
Oil derivatives
(18.0)
\u2013
(18.0)
(21.7)
\u2013
(21.7)
Total liabilities
(11.8)
\u2013
(11.8)
(35.0)
\u2013
(35.0)
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 in Level 1 which
are observable for the asset or liability, either directly or indirectly.
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 (2023: 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 Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2024 $m $m $m
Derivative assets
0.4
(0.3)
0.1
Derivative liabilities
(12.2)
0.3
(11.9)
Gross Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
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 2024 and 31 December 2023, 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 2024, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production
entitlements in the first half of 2025 with c.$59/bbl weighted average floors across all structures; while retaining strategic
upside participation across for the same period, with only c.5% of forecast production entitlements capped with collars
at a weighted average sold call of c.$92/bbl and the remainder of hedged barrels secured with three-way collars with
$92\u2013$102 call spreads for c.40% of the portfolio.
Similarly in the second half of 2025, Tullow\u2019s hedge portfolio provides downside protection for c.55% of forecast
production entitlements with c.$60/bbl weighted average floors across all structures; for the same period, c.16.% of
forecast production entitlements is capped at weighted average sold calls of c.$89/bbl while c.30% of secured with
three-way collars.
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 2025 hedge portfolio at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight puts
9,500
$58.47
\u2013
\u2013
Collars
2,000
$60.00
$91.94
\u2013
Three-way collars (call spread)
16,500
$59.05
$92.02
$102.02
Total/weighted average
28,000
$58.92
$92.01
$102.02
Bought put Bought
Second half of 2025 hedge position at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight Puts
4,500
$59.94
\u2013
\u2013
Collars
7,000
$60.00
$89.05
\u2013
Three-way collars (call spread)
12,500
$59.20
$83.64
$93.64
Total/weighted average
24,000
$59.57
$85.58
$93.64
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 2024 2023
31 Dec 2024 $m $m
Brent oil price
25%
(23.9)
(95.3)
Brent oil price
(25%)
42.8
24.2
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:
2024 2023
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
0.1
(18.9)
Oil derivatives \u2013 time value
(12.1)
(16.3)
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:
2024 2023
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(18.9)
(150.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Revaluation (losses)/gains arising in the year
(28.5)
20.1
19.0
131.4
At 31 December
0.1
(18.9)
2024 2023
Deferred amounts in the hedge reserve \u2013 time value $m $m
At 1 January
(16.3)
(94.4)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
26.1
27.8
Revaluation (losses)/gains arising in the year
(21.9)
50.3
4.2
78.1
At 31 December
(12.1)
(16.3)
2024 2023
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Deferred premium paid
26.1
27.8
Net losses from commodity derivatives in sales revenue (note 2)
73.6
139.1
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 years 2023 and 2024, the Group was exposed to interest rate risk on the
Secured Notes Facility (note 16), which could be fixed in advance from one to six months at rates determined by USD SOFR.
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 2024 and 2023, was as follows:
2024 2023
Cash and 2024 2024 Cash and 2023 2023
cash Fixed rate Floating rate 2024 cash Fixed rate Floating rate 2023
equivalents debt debt Total equivalents debt debt Total
$m $m $m $m $m $m $m $m
US$
548.6
(1,863.8)
(112.0)
(1,427.2)
492.3
(1,977.8)
(129.6)
(1,615.1)
Euro
0.2
\u2013
\u2013
0.2
0.6
\u2013
\u2013
0.6
Sterling
4.9
\u2013
\u2013
4.9
4.1
\u2013
\u2013
4.1
Other
1.4
\u2013
\u2013
1.4
2.0
\u2013
\u2013
2.0
555.1
(1,863.8)
(112.0)
(1,420.7)
499.0
(1,977.8)
(129.6)
(1,608.4)
Most of the Group\u2019s cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2024
and 31 December 2023.
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
2024 2023 2024 2023
Market movement $m $m $m $m
Interest rate
100 basis points
4.3
3.6
4.3
3.6
Interest rate
(10) basis points
(1.1)
(0.9)
(1.1)
(0.9)
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 2024, the Group\u2019s crude sales were predominantly made to Glencore.
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 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 2024 was $1,376.4 million (2023: $1,373.1 million).
Amount and movement of expected credit losses are disclosed in note 12.
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 2024 (2023: 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 2024, the only material monetary assets or liabilities of the Group that were not denominated in
the functional currency of the respective subsidiaries involved were $6.2 million in non-US dollar-denominated cash
and cash equivalents (2023: $6.7 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
2024 2023 2024 2023
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.0
1.1
1.0
1.1
US$/foreign currency exchange rates
(20%)
(1.6)
(1.7)
(1.6)
(1.7)
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 $0.7 billion (2023: $1.0 billion) of total
facility headroom and free cash as at 31 December 2024.
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 2024
Non-interest bearing
n/a
99.8
3.2
69.5
84.9
\u2013
257.4
Lease liabilities
16.4%
37.2
38.9
172.8
611.7
213.6
1,074.2
Fixed interest rate instruments
9.8%
Principal repayments
\u2013
492.5
100.0
1,285.2
\u2013
1,877.7
Interest charge
\u2013
17.2
136.7
65.8
\u2013
219.7
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
4.8
\u2013
13.5
53.8
\u2013
72.1
Total
141.8
551.8
492.5
2,231.4
213.6
3,631.1
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
7 7.8
520.8
3,093.4
337.5
4,124.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-431": { "value": "Note 16. Borrowings
2024 2023
$m $m
Current
Borrowings \u2013 within one year
7.00% Senior Notes due 2025
489.4
\u2013
10.25% Senior Secured Notes due 2026
100.0
100.0
589.4
100.0
2024 2023
$m $m
Non-current
Borrowings \u2013 after one year but within five years
7.00% Senior Notes due 2025
\u2013
489.0
10.25% Senior Secured Notes due 2026
1,274.4
1,371.0
Secured Notes Facility due 2028
112.0
124.6
1,386.4
1,984.6
Carrying value of total borrowings
1,975.8
2,084.6
The Group\u2019s capital structure includes $1,385 million Senior Secured Notes due in May 2026 (2026 Notes), $493 million Senior Notes due in March 2025 (2025 Notes), a $400 million Secured Notes Facility and a $250 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 2024, the Group made a mandatory prepayment of $100 million of the 2026 Notes. The 2025 Notes are due in a single payment in March 2025. The Company extended the maturity of its SSRCF from December 2024 to June 2025. The size of the facility also reduced from $500 million to $250 million to align with lower headroom needs and to continue to reduce financing costs, with all other terms unchanged. The SSRCF remains undrawn as at 31 December 2024. Unamortised debt arrangement fees for the 2026 Notes, 2025 Notes, Secured Notes Facility and the SSRCF are $10.9 million (2023: $14.3 million), $3.1 million (2023: $3.6 million), $17.7 million (2023: $5.0 million) and $nil million (2023: $2.3 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 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, 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 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 1.1 times 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 refinance, retire or purchase any or all of its outstanding debt through new debt refinancings and/or cash purchases, in open-market purchases, privately negotiated transactions or otherwise. Such refinancings or repurchases, if any, will be upon such terms and at such prices as management may determine, and will depend on prevailing market conditions, liquidity requirements and other factors. 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. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-481": { "value": "Note 17. Financial instruments Tullow is permitted to refinance the 2025 Notes with new indebtedness which is unsecured and ranks junior to the Secured Notes Facility. 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 is monitored and reviewed internally on a regular basis. The Group does not enter into or trade financial instruments, including derivatives, for speculative purposes.
2024 2023
$m $m
Financial assets
Financial assets at amortised cost
Trade receivables
137.9
43.5
Amounts due from Joint Venture Partners
683.4
830.6
Cash and cash equivalents
555.1
499.0
Derivative financial instruments
Used for hedging
0.1
\u2013
1,376.5
1,373.1
Financial liabilities
Liabilities at amortised cost
Trade payables
160.6
84.5
Other payables
508.9
567.0
Borrowings
1,975.8
2,084.6
Lease liabilities
732.9
906.7
Derivative financial instruments
Used for hedging
11.9
35.0
3,390.1
3,67
7.8
Fair values of financial assets and liabilities With the exception of the 2026 Notes, the 2025 Notes and the Secured Notes Facility, 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 2024 was $1,188.2 million (2023: $1,327.3 million) and $418.7 million (2023: $458.3 million) respectively. These are compared to their carrying value of $1,374.4 million (2023: $1,470.9 million) and $489.5 million (2023: $489.0 million). The fair value of the Secured Notes Facility was $128.4 million (2023: $130.0 million), estimated by discounting future cash flows by the relevant market rates at the balance sheet date. The 2026 Notes and the 2025 Notes are categorised as Level 1 in the fair value hierarchy. Except for expected credit losses as disclosed in note 12, no other 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:
2024 2024 2023 2023
Less than 1\u20133 2024 Less than 1\u20133 2023
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
6.2
\u2013
6.2
(13.3)
\u2013
(13.3)
Deferred premium
Oil derivatives
(18.0)
\u2013
(18.0)
(21.7)
\u2013
(21.7)
Total liabilities
(11.8)
\u2013
(11.8)
(35.0)
\u2013
(35.0)
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 in Level 1 which are observable for the asset or liability, either directly or indirectly. 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 (2023: 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 Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2024 $m $m $m
Derivative assets
0.4
(0.3)
0.1
Derivative liabilities
(12.2)
0.3
(11.9)
Gross Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
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 2024 and 31 December 2023, 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 2024, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2025 with c.$59/bbl weighted average floors across all structures; while retaining strategic upside participation across for the same period, with only c.5% of forecast production entitlements capped with collars at a weighted average sold call of c.$92/bbl and the remainder of hedged barrels secured with three-way collars with $92\u2013$102 call spreads for c.40% of the portfolio. Similarly in the second half of 2025, Tullow\u2019s hedge portfolio provides downside protection for c.55% of forecast production entitlements with c.$60/bbl weighted average floors across all structures; for the same period, c.16.% of forecast production entitlements is capped at weighted average sold calls of c.$89/bbl while c.30% of secured with three-way collars. 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 2025 hedge portfolio at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight puts
9,500
$58.47
\u2013
\u2013
Collars
2,000
$60.00
$91.94
\u2013
Three-way collars (call spread)
16,500
$59.05
$92.02
$102.02
Total/weighted average
28,000
$58.92
$92.01
$102.02
Bought put Bought
Second half of 2025 hedge position at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight Puts
4,500
$59.94
\u2013
\u2013
Collars
7,000
$60.00
$89.05
\u2013
Three-way collars (call spread)
12,500
$59.20
$83.64
$93.64
Total/weighted average
24,000
$59.57
$85.58
$93.64
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 2024 2023
31 Dec 2024 $m $m
Brent oil price
25%
(23.9)
(95.3)
Brent oil price
(25%)
42.8
24.2
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:
2024 2023
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
0.1
(18.9)
Oil derivatives \u2013 time value
(12.1)
(16.3)
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:
2024 2023
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(18.9)
(150.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Revaluation (losses)/gains arising in the year
(28.5)
20.1
19.0
131.4
At 31 December
0.1
(18.9)
2024 2023
Deferred amounts in the hedge reserve \u2013 time value $m $m
At 1 January
(16.3)
(94.4)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
26.1
27.8
Revaluation (losses)/gains arising in the year
(21.9)
50.3
4.2
78.1
At 31 December
(12.1)
(16.3)
2024 2023
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Deferred premium paid
26.1
27.8
Net losses from commodity derivatives in sales revenue (note 2)
73.6
139.1
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 years 2023 and 2024, the Group was exposed to interest rate risk on the Secured Notes Facility (note 16), which could be fixed in advance from one to six months at rates determined by USD SOFR. 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 2024 and 2023, was as follows:
2024 2023
Cash and 2024 2024 Cash and 2023 2023
cash Fixed rate Floating rate 2024 cash Fixed rate Floating rate 2023
equivalents debt debt Total equivalents debt debt Total
$m $m $m $m $m $m $m $m
US$
548.6
(1,863.8)
(112.0)
(1,427.2)
492.3
(1,977.8)
(129.6)
(1,615.1)
Euro
0.2
\u2013
\u2013
0.2
0.6
\u2013
\u2013
0.6
Sterling
4.9
\u2013
\u2013
4.9
4.1
\u2013
\u2013
4.1
Other
1.4
\u2013
\u2013
1.4
2.0
\u2013
\u2013
2.0
555.1
(1,863.8)
(112.0)
(1,420.7)
499.0
(1,977.8)
(129.6)
(1,608.4)
Most of the Group\u2019s cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2024 and 31 December 2023. 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
2024 2023 2024 2023
Market movement $m $m $m $m
Interest rate
100 basis points
4.3
3.6
4.3
3.6
Interest rate
(10) basis points
(1.1)
(0.9)
(1.1)
(0.9)
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 2024, the Group\u2019s crude sales were predominantly made to Glencore. 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 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 2024 was $1,376.4 million (2023: $1,373.1 million). Amount and movement of expected credit losses are disclosed in note 12. 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 2024 (2023: 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 2024, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.2 million in non-US dollar-denominated cash and cash equivalents (2023: $6.7 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
2024 2023 2024 2023
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.0
1.1
1.0
1.1
US$/foreign currency exchange rates
(20%)
(1.6)
(1.7)
(1.6)
(1.7)
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 $0.7 billion (2023: $1.0 billion) of total facility headroom and free cash as at 31 December 2024. 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 2024
Non-interest bearing
n/a
99.8
3.2
69.5
84.9
\u2013
257.4
Lease liabilities
16.4%
37.2
38.9
172.8
611.7
213.6
1,074.2
Fixed interest rate instruments
9.8%
Principal repayments
\u2013
492.5
100.0
1,285.2
\u2013
1,877.7
Interest charge
\u2013
17.2
136.7
65.8
\u2013
219.7
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
4.8
\u2013
13.5
53.8
\u2013
72.1
Total
141.8
551.8
492.5
2,231.4
213.6
3,631.1
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
7 7.8
520.8
3,093.4
337.5
4,124.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-458": { "value": "
2024 2023
$m $m
Financial assets
Financial assets at amortised cost
Trade receivables
137.9
43.5
Amounts due from Joint Venture Partners
683.4
830.6
Cash and cash equivalents
555.1
499.0
Derivative financial instruments
Used for hedging
0.1
\u2013
1,376.5
1,373.1
Financial liabilities
Liabilities at amortised cost
Trade payables
160.6
84.5
Other payables
508.9
567.0
Borrowings
1,975.8
2,084.6
Lease liabilities
732.9
906.7
Derivative financial instruments
Used for hedging
11.9
35.0
3,390.1
3,67
7.8
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-469": { "value": "
2024 2023
$m $m
Financial assets
Financial assets at amortised cost
Trade receivables
137.9
43.5
Amounts due from Joint Venture Partners
683.4
830.6
Cash and cash equivalents
555.1
499.0
Derivative financial instruments
Used for hedging
0.1
\u2013
1,376.5
1,373.1
Financial liabilities
Liabilities at amortised cost
Trade payables
160.6
84.5
Other payables
508.9
567.0
Borrowings
1,975.8
2,084.6
Lease liabilities
732.9
906.7
Derivative financial instruments
Used for hedging
11.9
35.0
3,390.1
3,67
7.8
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-459": { "value": "Fair values of financial assets and liabilities With the exception of the 2026 Notes, the 2025 Notes and the Secured Notes Facility, 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 2024 was $1,188.2 million (2023: $1,327.3 million) and $418.7 million (2023: $458.3 million) respectively. These are compared to their carrying value of $1,374.4 million (2023: $1,470.9 million) and $489.5 million (2023: $489.0 million). The fair value of the Secured Notes Facility was $128.4 million (2023: $130.0 million), estimated by discounting future cash flows by the relevant market rates at the balance sheet date. The 2026 Notes and the 2025 Notes are categorised as Level 1 in the fair value hierarchy. Except for expected credit losses as disclosed in note 12, no other 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:
2024 2024 2023 2023
Less than 1\u20133 2024 Less than 1\u20133 2023
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
6.2
\u2013
6.2
(13.3)
\u2013
(13.3)
Deferred premium
Oil derivatives
(18.0)
\u2013
(18.0)
(21.7)
\u2013
(21.7)
Total liabilities
(11.8)
\u2013
(11.8)
(35.0)
\u2013
(35.0)
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 in Level 1 which are observable for the asset or liability, either directly or indirectly. 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 (2023: 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-432": { "value": "Fair values of financial assets and liabilities With the exception of the 2026 Notes, the 2025 Notes and the Secured Notes Facility, 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 2024 was $1,188.2 million (2023: $1,327.3 million) and $418.7 million (2023: $458.3 million) respectively. These are compared to their carrying value of $1,374.4 million (2023: $1,470.9 million) and $489.5 million (2023: $489.0 million). The fair value of the Secured Notes Facility was $128.4 million (2023: $130.0 million), estimated by discounting future cash flows by the relevant market rates at the balance sheet date. The 2026 Notes and the 2025 Notes are categorised as Level 1 in the fair value hierarchy. Except for expected credit losses as disclosed in note 12, no other 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:
2024 2024 2023 2023
Less than 1\u20133 2024 Less than 1\u20133 2023
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
6.2
\u2013
6.2
(13.3)
\u2013
(13.3)
Deferred premium
Oil derivatives
(18.0)
\u2013
(18.0)
(21.7)
\u2013
(21.7)
Total liabilities
(11.8)
\u2013
(11.8)
(35.0)
\u2013
(35.0)
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 in Level 1 which are observable for the asset or liability, either directly or indirectly. 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 (2023: 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-476": { "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:
2024 2024 2023 2023
Less than 1\u20133 2024 Less than 1\u20133 2023
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
6.2
\u2013
6.2
(13.3)
\u2013
(13.3)
Deferred premium
Oil derivatives
(18.0)
\u2013
(18.0)
(21.7)
\u2013
(21.7)
Total liabilities
(11.8)
\u2013
(11.8)
(35.0)
\u2013
(35.0)
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 in Level 1 which are observable for the asset or liability, either directly or indirectly. 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 (2023: 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 Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2024 $m $m $m
Derivative assets
0.4
(0.3)
0.1
Derivative liabilities
(12.2)
0.3
(11.9)
Gross Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
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 2024 and 31 December 2023, 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 2024, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2025 with c.$59/bbl weighted average floors across all structures; while retaining strategic upside participation across for the same period, with only c.5% of forecast production entitlements capped with collars at a weighted average sold call of c.$92/bbl and the remainder of hedged barrels secured with three-way collars with $92\u2013$102 call spreads for c.40% of the portfolio. Similarly in the second half of 2025, Tullow\u2019s hedge portfolio provides downside protection for c.55% of forecast production entitlements with c.$60/bbl weighted average floors across all structures; for the same period, c.16.% of forecast production entitlements is capped at weighted average sold calls of c.$89/bbl while c.30% of secured with three-way collars. 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 2025 hedge portfolio at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight puts
9,500
$58.47
\u2013
\u2013
Collars
2,000
$60.00
$91.94
\u2013
Three-way collars (call spread)
16,500
$59.05
$92.02
$102.02
Total/weighted average
28,000
$58.92
$92.01
$102.02
Bought put Bought
Second half of 2025 hedge position at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight Puts
4,500
$59.94
\u2013
\u2013
Collars
7,000
$60.00
$89.05
\u2013
Three-way collars (call spread)
12,500
$59.20
$83.64
$93.64
Total/weighted average
24,000
$59.57
$85.58
$93.64
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 2024 2023
31 Dec 2024 $m $m
Brent oil price
25%
(23.9)
(95.3)
Brent oil price
(25%)
42.8
24.2
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:
2024 2023
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
0.1
(18.9)
Oil derivatives \u2013 time value
(12.1)
(16.3)
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:
2024 2023
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(18.9)
(150.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Revaluation (losses)/gains arising in the year
(28.5)
20.1
19.0
131.4
At 31 December
0.1
(18.9)
2024 2023
Deferred amounts in the hedge reserve \u2013 time value $m $m
At 1 January
(16.3)
(94.4)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
26.1
27.8
Revaluation (losses)/gains arising in the year
(21.9)
50.3
4.2
78.1
At 31 December
(12.1)
(16.3)
2024 2023
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Deferred premium paid
26.1
27.8
Net losses from commodity derivatives in sales revenue (note 2)
73.6
139.1
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 years 2023 and 2024, the Group was exposed to interest rate risk on the Secured Notes Facility (note 16), which could be fixed in advance from one to six months at rates determined by USD SOFR. 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 2024 and 2023, was as follows:
2024 2023
Cash and 2024 2024 Cash and 2023 2023
cash Fixed rate Floating rate 2024 cash Fixed rate Floating rate 2023
equivalents debt debt Total equivalents debt debt Total
$m $m $m $m $m $m $m $m
US$
548.6
(1,863.8)
(112.0)
(1,427.2)
492.3
(1,977.8)
(129.6)
(1,615.1)
Euro
0.2
\u2013
\u2013
0.2
0.6
\u2013
\u2013
0.6
Sterling
4.9
\u2013
\u2013
4.9
4.1
\u2013
\u2013
4.1
Other
1.4
\u2013
\u2013
1.4
2.0
\u2013
\u2013
2.0
555.1
(1,863.8)
(112.0)
(1,420.7)
499.0
(1,977.8)
(129.6)
(1,608.4)
Most of the Group\u2019s cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2024 and 31 December 2023. 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
2024 2023 2024 2023
Market movement $m $m $m $m
Interest rate
100 basis points
4.3
3.6
4.3
3.6
Interest rate
(10) basis points
(1.1)
(0.9)
(1.1)
(0.9)
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 2024, the Group\u2019s crude sales were predominantly made to Glencore. 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 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 2024 was $1,376.4 million (2023: $1,373.1 million). Amount and movement of expected credit losses are disclosed in note 12. 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 2024 (2023: 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 2024, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.2 million in non-US dollar-denominated cash and cash equivalents (2023: $6.7 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
2024 2023 2024 2023
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.0
1.1
1.0
1.1
US$/foreign currency exchange rates
(20%)
(1.6)
(1.7)
(1.6)
(1.7)
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 $0.7 billion (2023: $1.0 billion) of total facility headroom and free cash as at 31 December 2024. 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 2024
Non-interest bearing
n/a
99.8
3.2
69.5
84.9
\u2013
257.4
Lease liabilities
16.4%
37.2
38.9
172.8
611.7
213.6
1,074.2
Fixed interest rate instruments
9.8%
Principal repayments
\u2013
492.5
100.0
1,285.2
\u2013
1,877.7
Interest charge
\u2013
17.2
136.7
65.8
\u2013
219.7
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
4.8
\u2013
13.5
53.8
\u2013
72.1
Total
141.8
551.8
492.5
2,231.4
213.6
3,631.1
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
7 7.8
520.8
3,093.4
337.5
4,124.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfHedgeAccountingExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-470": { "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:
2024 2024 2023 2023
Less than 1\u20133 2024 Less than 1\u20133 2023
1 year years Total 1 year years Total
Assets/liabilities $m $m $m $m $m $m
Cash flow hedges
Oil derivatives
6.2
\u2013
6.2
(13.3)
\u2013
(13.3)
Deferred premium
Oil derivatives
(18.0)
\u2013
(18.0)
(21.7)
\u2013
(21.7)
Total liabilities
(11.8)
\u2013
(11.8)
(35.0)
\u2013
(35.0)
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 in Level 1 which are observable for the asset or liability, either directly or indirectly. 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 (2023: 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 Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2024 $m $m $m
Derivative assets
0.4
(0.3)
0.1
Derivative liabilities
(12.2)
0.3
(11.9)
Gross Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
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 2024 and 31 December 2023, 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 2024, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2025 with c.$59/bbl weighted average floors across all structures; while retaining strategic upside participation across for the same period, with only c.5% of forecast production entitlements capped with collars at a weighted average sold call of c.$92/bbl and the remainder of hedged barrels secured with three-way collars with $92\u2013$102 call spreads for c.40% of the portfolio. Similarly in the second half of 2025, Tullow\u2019s hedge portfolio provides downside protection for c.55% of forecast production entitlements with c.$60/bbl weighted average floors across all structures; for the same period, c.16.% of forecast production entitlements is capped at weighted average sold calls of c.$89/bbl while c.30% of secured with three-way collars. 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 2025 hedge portfolio at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight puts
9,500
$58.47
\u2013
\u2013
Collars
2,000
$60.00
$91.94
\u2013
Three-way collars (call spread)
16,500
$59.05
$92.02
$102.02
Total/weighted average
28,000
$58.92
$92.01
$102.02
Bought put Bought
Second half of 2025 hedge position at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight Puts
4,500
$59.94
\u2013
\u2013
Collars
7,000
$60.00
$89.05
\u2013
Three-way collars (call spread)
12,500
$59.20
$83.64
$93.64
Total/weighted average
24,000
$59.57
$85.58
$93.64
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 2024 2023
31 Dec 2024 $m $m
Brent oil price
25%
(23.9)
(95.3)
Brent oil price
(25%)
42.8
24.2
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:
2024 2023
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
0.1
(18.9)
Oil derivatives \u2013 time value
(12.1)
(16.3)
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:
2024 2023
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(18.9)
(150.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Revaluation (losses)/gains arising in the year
(28.5)
20.1
19.0
131.4
At 31 December
0.1
(18.9)
2024 2023
Deferred amounts in the hedge reserve \u2013 time value $m $m
At 1 January
(16.3)
(94.4)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
26.1
27.8
Revaluation (losses)/gains arising in the year
(21.9)
50.3
4.2
78.1
At 31 December
(12.1)
(16.3)
2024 2023
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Deferred premium paid
26.1
27.8
Net losses from commodity derivatives in sales revenue (note 2)
73.6
139.1
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 years 2023 and 2024, the Group was exposed to interest rate risk on the Secured Notes Facility (note 16), which could be fixed in advance from one to six months at rates determined by USD SOFR. 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 2024 and 2023, was as follows:
2024 2023
Cash and 2024 2024 Cash and 2023 2023
cash Fixed rate Floating rate 2024 cash Fixed rate Floating rate 2023
equivalents debt debt Total equivalents debt debt Total
$m $m $m $m $m $m $m $m
US$
548.6
(1,863.8)
(112.0)
(1,427.2)
492.3
(1,977.8)
(129.6)
(1,615.1)
Euro
0.2
\u2013
\u2013
0.2
0.6
\u2013
\u2013
0.6
Sterling
4.9
\u2013
\u2013
4.9
4.1
\u2013
\u2013
4.1
Other
1.4
\u2013
\u2013
1.4
2.0
\u2013
\u2013
2.0
555.1
(1,863.8)
(112.0)
(1,420.7)
499.0
(1,977.8)
(129.6)
(1,608.4)
Most of the Group\u2019s cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2024 and 31 December 2023. 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
2024 2023 2024 2023
Market movement $m $m $m $m
Interest rate
100 basis points
4.3
3.6
4.3
3.6
Interest rate
(10) basis points
(1.1)
(0.9)
(1.1)
(0.9)
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 2024, the Group\u2019s crude sales were predominantly made to Glencore. 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 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 2024 was $1,376.4 million (2023: $1,373.1 million). Amount and movement of expected credit losses are disclosed in note 12. 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 2024 (2023: 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 2024, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.2 million in non-US dollar-denominated cash and cash equivalents (2023: $6.7 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
2024 2023 2024 2023
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.0
1.1
1.0
1.1
US$/foreign currency exchange rates
(20%)
(1.6)
(1.7)
(1.6)
(1.7)
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 $0.7 billion (2023: $1.0 billion) of total facility headroom and free cash as at 31 December 2024. 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 2024
Non-interest bearing
n/a
99.8
3.2
69.5
84.9
\u2013
257.4
Lease liabilities
16.4%
37.2
38.9
172.8
611.7
213.6
1,074.2
Fixed interest rate instruments
9.8%
Principal repayments
\u2013
492.5
100.0
1,285.2
\u2013
1,877.7
Interest charge
\u2013
17.2
136.7
65.8
\u2013
219.7
Variable interest rate instruments
15.8%
Principal repayments
\u2013
\u2013
\u2013
130.0
\u2013
130.0
Interest charge
4.8
\u2013
13.5
53.8
\u2013
72.1
Total
141.8
551.8
492.5
2,231.4
213.6
3,631.1
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
7 7.8
520.8
3,093.4
337.5
4,124.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-483": { "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 Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2024 $m $m $m
Derivative assets
0.4
(0.3)
0.1
Derivative liabilities
(12.2)
0.3
(11.9)
Gross Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
", "dimensions": { "concept": "ifrs-full:DisclosureOfOffsettingOfFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-460": { "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 Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2024 $m $m $m
Derivative assets
0.4
(0.3)
0.1
Derivative liabilities
(12.2)
0.3
(11.9)
Gross Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
", "dimensions": { "concept": "ifrs-full:DisclosureOfOffsettingOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-433": { "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 Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2024 $m $m $m
Derivative assets
0.4
(0.3)
0.1
Derivative liabilities
(12.2)
0.3
(11.9)
Gross Gross amounts Net amounts
amounts offset in Group presented in Group
recognised balance sheet balance sheet
31 December 2023 $m $m $m
Derivative assets
3.0
(3.0)
\u2013
Derivative liabilities
(38.0)
3.0
(35.0)
", "dimensions": { "concept": "ifrs-full:DisclosureOfOffsettingOfFinancialAssetsAndFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-484": { "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 2024 and 31 December 2023, 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 2024, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2025 with c.$59/bbl weighted average floors across all structures; while retaining strategic upside participation across for the same period, with only c.5% of forecast production entitlements capped with collars at a weighted average sold call of c.$92/bbl and the remainder of hedged barrels secured with three-way collars with $92\u2013$102 call spreads for c.40% of the portfolio. Similarly in the second half of 2025, Tullow\u2019s hedge portfolio provides downside protection for c.55% of forecast production entitlements with c.$60/bbl weighted average floors across all structures; for the same period, c.16.% of forecast production entitlements is capped at weighted average sold calls of c.$89/bbl while c.30% of secured with three-way collars. 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 2025 hedge portfolio at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight puts
9,500
$58.47
\u2013
\u2013
Collars
2,000
$60.00
$91.94
\u2013
Three-way collars (call spread)
16,500
$59.05
$92.02
$102.02
Total/weighted average
28,000
$58.92
$92.01
$102.02
Bought put Bought
Second half of 2025 hedge position at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight Puts
4,500
$59.94
\u2013
\u2013
Collars
7,000
$60.00
$89.05
\u2013
Three-way collars (call spread)
12,500
$59.20
$83.64
$93.64
Total/weighted average
24,000
$59.57
$85.58
$93.64
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 2024 2023
31 Dec 2024 $m $m
Brent oil price
25%
(23.9)
(95.3)
Brent oil price
(25%)
42.8
24.2
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:
2024 2023
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
0.1
(18.9)
Oil derivatives \u2013 time value
(12.1)
(16.3)
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:
2024 2023
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(18.9)
(150.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Revaluation (losses)/gains arising in the year
(28.5)
20.1
19.0
131.4
At 31 December
0.1
(18.9)
2024 2023
Deferred amounts in the hedge reserve \u2013 time value $m $m
At 1 January
(16.3)
(94.4)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
26.1
27.8
Revaluation (losses)/gains arising in the year
(21.9)
50.3
4.2
78.1
At 31 December
(12.1)
(16.3)
2024 2023
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Deferred premium paid
26.1
27.8
Net losses from commodity derivatives in sales revenue (note 2)
73.6
139.1
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 years 2023 and 2024, the Group was exposed to interest rate risk on the Secured Notes Facility (note 16), which could be fixed in advance from one to six months at rates determined by USD SOFR. 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 2024 and 2023, was as follows:
2024 2023
Cash and 2024 2024 Cash and 2023 2023
cash Fixed rate Floating rate 2024 cash Fixed rate Floating rate 2023
equivalents debt debt Total equivalents debt debt Total
$m $m $m $m $m $m $m $m
US$
548.6
(1,863.8)
(112.0)
(1,427.2)
492.3
(1,977.8)
(129.6)
(1,615.1)
Euro
0.2
\u2013
\u2013
0.2
0.6
\u2013
\u2013
0.6
Sterling
4.9
\u2013
\u2013
4.9
4.1
\u2013
\u2013
4.1
Other
1.4
\u2013
\u2013
1.4
2.0
\u2013
\u2013
2.0
555.1
(1,863.8)
(112.0)
(1,420.7)
499.0
(1,977.8)
(129.6)
(1,608.4)
Most of the Group\u2019s cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2024 and 31 December 2023. 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
2024 2023 2024 2023
Market movement $m $m $m $m
Interest rate
100 basis points
4.3
3.6
4.3
3.6
Interest rate
(10) basis points
(1.1)
(0.9)
(1.1)
(0.9)
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 2024 (2023: 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 2024, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.2 million in non-US dollar-denominated cash and cash equivalents (2023: $6.7 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
2024 2023 2024 2023
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.0
1.1
1.0
1.1
US$/foreign currency exchange rates
(20%)
(1.6)
(1.7)
(1.6)
(1.7)
", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-434": { "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 2024 and 31 December 2023, 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 2024, Tullow\u2019s hedge portfolio provides downside protection for c.60% of forecast production entitlements in the first half of 2025 with c.$59/bbl weighted average floors across all structures; while retaining strategic upside participation across for the same period, with only c.5% of forecast production entitlements capped with collars at a weighted average sold call of c.$92/bbl and the remainder of hedged barrels secured with three-way collars with $92\u2013$102 call spreads for c.40% of the portfolio. Similarly in the second half of 2025, Tullow\u2019s hedge portfolio provides downside protection for c.55% of forecast production entitlements with c.$60/bbl weighted average floors across all structures; for the same period, c.16.% of forecast production entitlements is capped at weighted average sold calls of c.$89/bbl while c.30% of secured with three-way collars. 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 2025 hedge portfolio at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight puts
9,500
$58.47
\u2013
\u2013
Collars
2,000
$60.00
$91.94
\u2013
Three-way collars (call spread)
16,500
$59.05
$92.02
$102.02
Total/weighted average
28,000
$58.92
$92.01
$102.02
Bought put Bought
Second half of 2025 hedge position at 31 December 2024
Bopd
(floor)
Sold call
call
Hedge structure
Straight Puts
4,500
$59.94
\u2013
\u2013
Collars
7,000
$60.00
$89.05
\u2013
Three-way collars (call spread)
12,500
$59.20
$83.64
$93.64
Total/weighted average
24,000
$59.57
$85.58
$93.64
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 2024 2023
31 Dec 2024 $m $m
Brent oil price
25%
(23.9)
(95.3)
Brent oil price
(25%)
42.8
24.2
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:
2024 2023
Cash flow hedge reserve $m $m
Oil derivatives \u2013 intrinsic
0.1
(18.9)
Oil derivatives \u2013 time value
(12.1)
(16.3)
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:
2024 2023
Deferred amounts in the hedge reserve \u2013 intrinsic $m $m
At 1 January
(18.9)
(150.3)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Revaluation (losses)/gains arising in the year
(28.5)
20.1
19.0
131.4
At 31 December
0.1
(18.9)
", "dimensions": { "concept": "tullowoilplc:DisclsoureOfCommodityRisk", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-435": { "value": "
2024 2023
Deferred amounts in the hedge reserve \u2013 time value $m $m
At 1 January
(16.3)
(94.4)
Reclassification adjustments for items included in the income statement on realisation:
Oil derivatives \u2013 transferred to sales revenue
26.1
27.8
Revaluation (losses)/gains arising in the year
(21.9)
50.3
4.2
78.1
At 31 December
(12.1)
(16.3)
2024 2023
Reconciliation to sales revenue $m $m
Oil derivatives \u2013 transferred to sales revenue
47.5
111.3
Deferred premium paid
26.1
27.8
Net losses from commodity derivatives in sales revenue (note 2)
73.6
139.1
", "dimensions": { "concept": "ifrs-full:DisclosureOfDetailedInformationAboutHedgesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-436": { "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 years 2023 and 2024, the Group was exposed to interest rate risk on the Secured Notes Facility (note 16), which could be fixed in advance from one to six months at rates determined by USD SOFR. 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 2024 and 2023, was as follows:
2024 2023
Cash and 2024 2024 Cash and 2023 2023
cash Fixed rate Floating rate 2024 cash Fixed rate Floating rate 2023
equivalents debt debt Total equivalents debt debt Total
$m $m $m $m $m $m $m $m
US$
548.6
(1,863.8)
(112.0)
(1,427.2)
492.3
(1,977.8)
(129.6)
(1,615.1)
Euro
0.2
\u2013
\u2013
0.2
0.6
\u2013
\u2013
0.6
Sterling
4.9
\u2013
\u2013
4.9
4.1
\u2013
\u2013
4.1
Other
1.4
\u2013
\u2013
1.4
2.0
\u2013
\u2013
2.0
555.1
(1,863.8)
(112.0)
(1,420.7)
499.0
(1,977.8)
(129.6)
(1,608.4)
Most of the Group\u2019s cash and cash equivalents consisted of balances earning variable interest rates as at 31 December 2024 and 31 December 2023. 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
2024 2023 2024 2023
Market movement $m $m $m $m
Interest rate
100 basis points
4.3
3.6
4.3
3.6
Interest rate
(10) basis points
(1.1)
(0.9)
(1.1)
(0.9)
", "dimensions": { "concept": "tullowoilplc:DisclosureOfInterestRateRisk", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-437": { "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 2024, the Group\u2019s crude sales were predominantly made to Glencore. 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 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 2024 was $1,376.4 million (2023: $1,373.1 million). Amount and movement of expected credit losses are disclosed in note 12. ", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-438": { "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 2024 (2023: 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 2024, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were $6.2 million in non-US dollar-denominated cash and cash equivalents (2023: $6.7 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
2024 2023 2024 2023
Market movement $m $m $m $m
US$/foreign currency exchange rates
20%
1.0
1.1
1.0
1.1
US$/foreign currency exchange rates
(20%)
(1.6)
(1.7)
(1.6)
(1.7)
", "dimensions": { "concept": "tullowoilplc:DisclosureOfForeignCurrencyRisk", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-393": { "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 December 31 December 31 December 31 December
Right-of-use assets (included in property, 2024 2023 2024 2023
plant and equipment) and lease liabilities $m $m $m $m
Property leases
18.2
22.0
26.1
27.6
Oil and gas production and support equipment leases
466.4
576.9
661.9
826.4
Transportation equipment leases
19.8
25.1
44.9
52.7
Total
504.4
624.0
732.9
906.7
Current
151.9
185.7
Non-current
581.0
721.0
Total
732.9
906.7
Additions and disposals of right-of-use assets during the 2024 financial year were $1.4 million and $145.3 million,
respectively. 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 oil and gas production and support equipment.
During 2023, 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 price of the extension option.
The resulting lease liability remeasurement had the following impact on balances:
$m
Lease liability
(39.2)
Right-of-use asset (included in property, plant and equipment)
25.6
Amounts due from Joint Venture Partners
13.6
As at 31 December 2024, the present value of the TEN FPSO right-of-use asset was $466.3 million (2023: $549.0 million).
The present value of the TEN FPSO gross lease liability was $650.0 million (2023: $763.5 million).
A receivable from the Joint Venture Partners of $244.9 million (2023: $288.8 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 in the 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 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 1 January 2024
(906.7)
349.5
(557.2)
Additions and changes in lease estimates
1.6
1.2
2.8
Payments/(receipts)
291.6
(122.6)
169.0
Interest (expense)/income
(119.7)
48.1
(71.6)
Currency translation adjustments
0.3
\u2013
0.3
At 31 December 2024
(732.9)
276.2
(456.7)
ii) Amounts recognised in the statement of profit or loss
31 December 31 December
2024 2023
$m $m
Depreciation charge of right-of-use assets
Property leases
8.5
7.3
Oil and gas production and support equipment leases
82.9
74.1
Total
91.4
81.4
Interest expense on lease liabilities (included in finance cost)
119.7
78.6
Interest income on amounts due from Joint Venture Partners
(48.1)
(30.1)
Expense relating to short-term leases
0.8
1.0
Expense relating to leases of low-value assets
0.6
0.9
Total
164.4
131.8
The total net cash outflow for leases in 2024 was $169.0 million (2023: $195.0 million).
", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-394": { "value": "
Note 19. Provisions
Other Other
Decommissioning provisions Total Decommissioning provisions Total
2024 2024 2024 2023 2023 2023
Notes $m $m $m $m $m $m
At 1 January
377.9
93.7
471.6
398.1
116.3
514.4
New provisions
\u2013
22.4
22.4
\u2013
10.4
10.4
Changes in estimate
(39.3)
(75.9)
(115.2)
47.8
(32.3)
15.5
Acquisitions
1
5.8
\u2013
5.8
\u2013
\u2013
\u2013
Transfer to assets and liabilities held for sale
14
\u2013
\u2013
\u2013
(14.2)
\u2013
(14.2)
Payments
(49.0)
(0.7)
(49.7)
(66.4)
(0.6)
(67.0)
Unwinding of discount
5
11.4
\u2013
11.4
10.1
\u2013
10.1
Currency translation adjustment
(0.4)
(0.1)
(0.5)
2.5
(0.1)
2.4
At 31 December
306.4
39.4
345.8
377.9
93.7
471.6
Current provisions
2
9.8
14.5
24.3
53.4
14.5
67.9
Non-current provisions
2
296.6
24.9
321.5
324.5
79.2
403.7
1. This relates to an acquisition through business combination discussed in note 14.
2. In 2024, provisions of $10.0 million were reclassified from current provisions to non-current provisions as management expectations are that the
provision will not crystallise within the next 12 months.
Other provisions include non-income tax provisions of $7.1 million (2023: $38.8 million) and $32.3 million (2023: $54.9 million)
of disputed cases and claims. Management estimates non-current other provisions would fall due between two and
five years.
New other provisions include $7.1 million for the restructuring programme that commenced in December 2024.
Changes in estimate of other provisions includes a reduction of $31.1 million in relation to the BPRT arbitration ruling.
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 Group\u2019s interest.
The decommissioning provision represents the present value of decommissioning costs relating to the UK 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 pages 47 and 48
of the TCFD and note 25 Climate change and energy transition.
Discount Cessation of Discount Cessation of
rate production Total rate production Total
Inflation assumption assumption 2024 assumption assumption 2023
assumption
1
2024 2024 $m 2023 2023 $m
C\u00f4te d\u2019Ivoire
2.0%
4.5%
2027
50.0
3.5%
2032
47.1
Gabon
2.0%
4.5\u20135.0%
2030\u20132047
30.7
3.5\u20134%
2034\u20132047
28.7
Ghana
2.0%
4.5%
2033\u20132036
195.6
3.5%
2032\u20132036
208.2
Mauritania
n/a
n/a
2018
1.1
n/a
2018
54.7
UK
n/a
n/a
2018
29.0
n/a
2018
39.2
306.4
37 7.9
1. Short-term inflation rate assumption has increased from 2.0% to 2.5% in 2025. Long-term rates of 2% remained unchanged from 31 December 2023.
The Group\u2019s decommissioning activities are ongoing in the UK and Mauritania, with $10.0 million of the future costs
expected to be incurred in 2025. The remaining activities are planned to continue through to 2027, with an associated
expenditure of $20.0 million, mostly in the UK.
", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-477": { "value": "Note 19. Provisions
Other Other
Decommissioning provisions Total Decommissioning provisions Total
2024 2024 2024 2023 2023 2023
Notes $m $m $m $m $m $m
At 1 January
377.9
93.7
471.6
398.1
116.3
514.4
New provisions
\u2013
22.4
22.4
\u2013
10.4
10.4
Changes in estimate
(39.3)
(75.9)
(115.2)
47.8
(32.3)
15.5
Acquisitions
1
5.8
\u2013
5.8
\u2013
\u2013
\u2013
Transfer to assets and liabilities held for sale
14
\u2013
\u2013
\u2013
(14.2)
\u2013
(14.2)
Payments
(49.0)
(0.7)
(49.7)
(66.4)
(0.6)
(67.0)
Unwinding of discount
5
11.4
\u2013
11.4
10.1
\u2013
10.1
Currency translation adjustment
(0.4)
(0.1)
(0.5)
2.5
(0.1)
2.4
At 31 December
306.4
39.4
345.8
377.9
93.7
471.6
Current provisions
2
9.8
14.5
24.3
53.4
14.5
67.9
Non-current provisions
2
296.6
24.9
321.5
324.5
79.2
403.7
1. This relates to an acquisition through business combination discussed in note 14. 2. In 2024, provisions of $10.0 million were reclassified from current provisions to non-current provisions as management expectations are that the provision will not crystallise within the next 12 months. Other provisions include non-income tax provisions of $7.1 million (2023: $38.8 million) and $32.3 million (2023: $54.9 million) of disputed cases and claims. Management estimates non-current other provisions would fall due between two and five years. New other provisions include $7.1 million for the restructuring programme that commenced in December 2024. Changes in estimate of other provisions includes a reduction of $31.1 million in relation to the BPRT arbitration ruling. 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 Group\u2019s interest. The decommissioning provision represents the present value of decommissioning costs relating to the UK 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 pages 47 and 48 of the TCFD and note 25 Climate change and energy transition.
Discount Cessation of Discount Cessation of
rate production Total rate production Total
Inflation assumption assumption 2024 assumption assumption 2023
assumption
1
2024 2024 $m 2023 2023 $m
C\u00f4te d\u2019Ivoire
2.0%
4.5%
2027
50.0
3.5%
2032
47.1
Gabon
2.0%
4.5\u20135.0%
2030\u20132047
30.7
3.5\u20134%
2034\u20132047
28.7
Ghana
2.0%
4.5%
2033\u20132036
195.6
3.5%
2032\u20132036
208.2
Mauritania
n/a
n/a
2018
1.1
n/a
2018
54.7
UK
n/a
n/a
2018
29.0
n/a
2018
39.2
306.4
37 7.9
1. Short-term inflation rate assumption has increased from 2.0% to 2.5% in 2025. Long-term rates of 2% remained unchanged from 31 December 2023. The Group\u2019s decommissioning activities are ongoing in the UK and Mauritania, with $10.0 million of the future costs expected to be incurred in 2025. The remaining activities are planned to continue through to 2027, with an associated expenditure of $20.0 million, mostly in the UK. Note 23. Commitments and contingencies
2024 2023
$m $m
Capital commitments
248.1
207.0
Contingent liabilities
Performance guarantees
24.1
42.7
Other contingent liabilities
37.8
84.4
61.9
127.1
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. Changes in estimate of other contingent liabilities include a reduction of $46.6 million in relation to the BPRT arbitration ruling. The movement in capital commitments is predominantly due to the 2025 drilling programme in Ghana and higher capital expenditure budgeted for Gabon.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-461": { "value": "Note 20. Deferred taxation
Other Deferred
Accelerated tax Tax temporary petroleum
depreciation Decommissioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
0.2
0.2
At 1 January 2024
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
Credit/(charge) to income statement
41.5
(1.5)
(7.4)
26.2
(13.8)
(3.9)
41.1
Acquisitions
1
(44.9)
\u2013
\u2013
\u2013
\u2013
\u2013
(44.9)
At 31 December 2024
(443.6)
66.1
\u2013
(31.9)
2.0
2.7
(404.7)
1. This relates to an acquisition through business combination discussed in note 14.
2024 2023
$m $m
Deferred tax liabilities
(413.0)
(420.5)
Deferred tax assets
8.3
19.6
(404.7)
(400.9)
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-439": { "value": "Note 20. Deferred taxation
Other Deferred
Accelerated tax Tax temporary petroleum
depreciation Decommissioning losses differences Provisions revenue tax Total
$m $m $m $m $m $m $m
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
0.2
0.2
At 1 January 2024
(440.2)
67.6
7.4
(58.1)
15.8
6.6
(400.9)
Credit/(charge) to income statement
41.5
(1.5)
(7.4)
26.2
(13.8)
(3.9)
41.1
Acquisitions
1
(44.9)
\u2013
\u2013
\u2013
\u2013
\u2013
(44.9)
At 31 December 2024
(443.6)
66.1
\u2013
(31.9)
2.0
2.7
(404.7)
1. This relates to an acquisition through business combination discussed in note 14.
2024 2023
$m $m
Deferred tax liabilities
(413.0)
(420.5)
Deferred tax assets
8.3
19.6
(404.7)
(400.9)
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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-395": { "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 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 1 January 2024
1,452,541,887
216.7
1,294.7
Issued during the year
Exercise of share options
6,548,077
0.8
\u2013
At 31 December 2024
1,459,089,964
217.5
1,294.7
The Company does not have a maximum authorised share capital.
", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-440": { "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 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 1 January 2024
1,452,541,887
216.7
1,294.7
Issued during the year
Exercise of share options
6,548,077
0.8
\u2013
At 31 December 2024
1,459,089,964
217.5
1,294.7
The Company does not have a maximum authorised share capital.", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-396": { "value": "
Note 22. Share-based payments
Analysis of share-based payment charge
2024 2023
Notes $m $m
Tullow Incentive Plan
4.3
3.7
Employee Share Award Plan
1.9
1.4
2022
PDMR buyout award
0.4
0.5
2021
Tullow Sharesave Plan
0.3
0.4
6.9
6.0
Expensed to operating costs
4
0.4
0.4
Expensed as administrative cost
4
6.5
5.6
Total share-based payment charge
6.9
6.0
The national insurance liability as at 31 December 2024 was $1.0 million (2023: $1.9 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 93 to 112.
The weighted average remaining contractual life for TIP awards outstanding at 31 December 2024 was 6.7 years.
Employee Share Award Plan (ESAP)
Most Group employees are eligible to be granted nil exercise price options, which 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 2024 was 7.3 years.
2020 PDMR buyout awards
On 5 August 2020, the Company granted the new Chief Executive Officer a number of buyout awards following the
commencement of their employment in order to compensate them for certain share arrangements forfeited upon
leaving their former employer. The grant of the awards was conditional on the CEO purchasing shares in the Company
with a value of \u00a3350,000 (the 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 93 to 112.
The weighted average remaining contractual life for the PDMR buyout awards outstanding at 31 December 2024 was 5.5 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 2024 had exercise prices of 19p to 40p and remaining contractual lives
between 0.4 years and 3.4 years. The weighted average remaining contractual life is 2.4 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 LTIP awards, granted to date, 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 2024 Tullow Executive Share
Plan (LTIP) awards in the Remuneration report on pages 93 to 112.
The weighted average remaining contractual life for LTIP awards outstanding at 31 December 2024 was 8.9 years.
Deferred Annual Bonus awards (DAB)
Under the bonus scheme arrangements for the Executive Directors, one-third of any bonus earned will normally be
deferred into shares for a period of three years. Deferred bonus awards may take the form of nil-cost options, conditional
awards of shares or other such form as has a similar economic effect. Additional shares may be delivered in respect of
shares subject to deferred bonus awards to reflect the value of dividends paid during the period beginning with the date
of grant and ending with the date of vesting (this payment may assume that dividends had been reinvested in Tullow
shares on a cumulative basis).
The weighted average remaining contractual life for the DAB awards outstanding at 31 December 2024 was 9.2 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
2024
TIP \u2013
number of shares
26,689,263
6,986,505
3,740,350
1,
57 7,441
28,357,977
4,282,353
2024
TIP \u2013
average weighted share
price at grant
51.5
27.1
81.1
22.3
43.2
78.1
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
2024
ESAP \u2013
number of shares
18,081,093
7,172,118
2,764,203
1,258,792
21,230,216
5,412,450
2024
ESAP \u2013
average weighted share
price at grant
66.0
27.1
114.7
40.4
48.0
90.9
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
2024
Buyout awards \u2013 number of shares
9,000,000
\u2013
\u2013
\u2013
9,000,000
\u2013
2024
Buyout awards \u2013 WAEP
25.7
\u2013
\u2013
\u2013
25.7
\u2013
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
2024
DAB awards \u2013
number of shares
\u2013
338,652
\u2013
\u2013
338,652
\u2013
2024
DAB awards \u2013
WAEP
\u2013
27.1
\u2013
\u2013
27.1
\u2013
2023
DAB awards \u2013
number of shares
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
2023
DAB awards \u2013
WAEP
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
2024
LTIP
number of shares
12,241,264
14,544,167
\u2013
2,261,654
24,523,777
\u2013
2024
LTIP
average weighted share
price at grant
27.7
27.1
\u2013
27.4
27.4
\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
2024
SAYE \u2013
number of options
2,393,498
2,025,823
\u2013
818,170
3,601,151
\u2013
2024
SAYE \u2013
WAEP
36.5
19.0
\u2013
43.5
26.9
\u2013
2023
SAYE \u2013
number of options
2,387,871
558,411
\u2013
552,784
2,393,498
\u2013
2023
SAYE \u2013
WAEP
38.8
29.0
\u2013
45.4
36.5
\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, DAB and SAYE.
The following table details the weighted average fair value of awards granted and the assumptions used in the fair value
expense calculations.
2024 2024 2023 2024 2023 2024 2023 2024 2023
DAB LTIP LTIP ESAP ESAP TIP TIP SAYE SAYE
Weighted average fair value of awards granted
27.1p
10.2p
11.2p
27.1p
32.0p
27.1p
32.0p
12.1p
20.5p
Principal inputs to options valuations model:
Weighted average share price at grant
27.1p
27.1p
27.7p
27.1p
32.0p
27.1p
32.0p
24.4p
32.3p
Weighted average exercise price
0.0p
0.0p
0.0p
0.0p
0.0p
0.0p
0.0p
19.0p
29.0p
Risk-free interest rate per annum
1
4.2%
4.2%
5.0%
4.2%
3.5%
4.2%
3.5%
4.1%
4.5%
Expected volatility per annum
1, 2
48%
48%
63%
48%
89%
48%/84%
89%/84%
56%
92%
Expected award life (years)
1, 3
3.0
3.0
2.7
3.0
3.0
3.0/5.0
3.0/5.0
3.6
3.6
Dividend yield per annum
4
n/a
n/a
n/a
n/a
n/a
n/a
n/a
0.0%
0.0%
Employee turnover before vesting per annum
1
0%
0%
0%
5%
5%
5%/0%
5%/0%
5%
5%
1. Shows the assumption for 2024 and 2023 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 2024 ESAP, TIP and DAB awards, and the 2023 ESAP and 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 2024 LTIP, ESAP, DAB and TIP awards as a dividend equivalent will be
payable on the exercise of these awards.
2024 2024
ESAP TIP
Weighted average share price at exercise for awards exercised
30.3p
30.0p
", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-397": { "value": "
Note 23. Commitments and contingencies
2024 2023
$m $m
Capital commitments
248.1
207.0
Contingent liabilities
Performance guarantees
24.1
42.7
Other contingent liabilities
37.8
84.4
61.9
127.1
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. Changes in estimate of other contingent liabilities include a reduction
of $46.6 million in relation to the BPRT arbitration ruling.
The movement in capital commitments is predominantly due to the 2025 drilling programme in Ghana and higher capital
expenditure budgeted for Gabon.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-462": { "value": "Note 23. Commitments and contingencies
2024 2023
$m $m
Capital commitments
248.1
207.0
Contingent liabilities
Performance guarantees
24.1
42.7
Other contingent liabilities
37.8
84.4
61.9
127.1
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. Changes in estimate of other contingent liabilities include a reduction of $46.6 million in relation to the BPRT arbitration ruling. The movement in capital commitments is predominantly due to the 2025 drilling programme in Ghana and higher capital expenditure budgeted for Gabon.", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-441": { "value": "Note 23. Commitments and contingencies
2024 2023
$m $m
Capital commitments
248.1
207.0
Contingent liabilities
Performance guarantees
24.1
42.7
Other contingent liabilities
37.8
84.4
61.9
127.1
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. Changes in estimate of other contingent liabilities include a reduction of $46.6 million in relation to the BPRT arbitration ruling. The movement in capital commitments is predominantly due to the 2025 drilling programme in Ghana and higher capital expenditure budgeted for Gabon.", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-398": { "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.
2024 2023
$m $m
Short-term employee benefits
3.0
2.7
Post-employment benefits
0.2
0.2
Share-based payments
1.5
1.4
4.7
4.3
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 93 to 112.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-463": { "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.
2024 2023
$m $m
Short-term employee benefits
3.0
2.7
Post-employment benefits
0.2
0.2
Share-based payments
1.5
1.4
4.7
4.3
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 93 to 112.", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-442": { "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.
2024 2023
$m $m
Short-term employee benefits
3.0
2.7
Post-employment benefits
0.2
0.2
Share-based payments
1.5
1.4
4.7
4.3
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 93 to 112.", "dimensions": { "concept": "ifrs-full:DisclosureOfTransactionsBetweenRelatedPartiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-399": { "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 pages 35 to 37.
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 makes progress in the energy transition.
Note (ag) key sources of estimation uncertainties describes those uncertainties that have the potential to have a material
effect on the Group balance sheet in the next 12 months.
This note describes the key areas of climate impacts that potentially have short- and longer-term effects on amounts
recognised on the Group balance sheet as at 31 December 2024. Where relevant, this note contains references to other
notes to the Group Financial Statements, and sections of the 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 end of 2025, and 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 the TCFD on pages 47 and 48 for details). Tullow continues to
assess operating cash flow (OCF) impact on our currently producing assets using the oil price assumptions in the
IEA scenarios.
The impact of acute and chronic physical climate risks on our existing assets is also assessed and meteorological and
climate conditions are incorporated into operational design considerations; please refer to the TCFD on page 46 for
probabilities, potential exposures and mitigations.
Tullow continues to monitor the landscape of compliance carbon mechanisms that may impact our business. In addition
to this 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 progressed to FID midway through 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 47 and 48 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": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-400": { "value": "
Note 26. Events since 31 December 2024
On 14 February 2025, Richard Miller was appointed as Interim Chief Executive Officer (CEO). Rahul Dhir stepped down
as Director from the Board of Tullow Oil plc.
On 3 March 2025, the Group settled the 2025 Notes upon maturity with a payment of $510 million, comprising a $493 million
principal repayment and $17 million final coupon. This payment was partially funded through a $270 million drawdown
from the Secured Notes Facility, with the remainder sourced from cash at bank. Following the $270 million drawdown,
the Secured Notes Facility was fully drawn at $400 million.
On 24 March 2025, Tullow announced that it had signed a binding heads of terms agreement with Gabon Oil Company
for the sale of Tullow Oil Gabon SA, which holds 100% of Tullow\u2019s working interests in Gabon for a total cash
consideration of $300 million net of tax. Signing of a sale and purchase agreement is targeted for the second quarter of
2025, with completion of the transaction and receipt of funds expected around the middle of the year, subject to receipt
of relevant governmental and regulatory approvals.
The transaction is a corporate sale of Tullow\u2019s entire Gabonese portfolio of assets, representing c.10 kbopd of 2025
production guidance and c.36 million barrels of 2P reserves. Conditions precedent for the completion of the Transaction
include all necessary approvals (including from government ministries), CEMAC Competition Commission approval and
Tullow\u2019s processing of the 2024 dividend in compliance with Gabonese requirements.
This is a non adjusting event as at 31 December 2024 as defined by IAS 10 Events after the Reporting Period.
There have not been any other events since 31 December 2024 that have resulted in a material impact on the year
end results.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-443": { "value": "Note 26. Events since 31 December 2024 On 14 February 2025, Richard Miller was appointed as Interim Chief Executive Officer (CEO). Rahul Dhir stepped down as Director from the Board of Tullow Oil plc. On 3 March 2025, the Group settled the 2025 Notes upon maturity with a payment of $510 million, comprising a $493 million principal repayment and $17 million final coupon. This payment was partially funded through a $270 million drawdown from the Secured Notes Facility, with the remainder sourced from cash at bank. Following the $270 million drawdown, the Secured Notes Facility was fully drawn at $400 million. On 24 March 2025, Tullow announced that it had signed a binding heads of terms agreement with Gabon Oil Company for the sale of Tullow Oil Gabon SA, which holds 100% of Tullow\u2019s working interests in Gabon for a total cash consideration of $300 million net of tax. Signing of a sale and purchase agreement is targeted for the second quarter of 2025, with completion of the transaction and receipt of funds expected around the middle of the year, subject to receipt of relevant governmental and regulatory approvals. The transaction is a corporate sale of Tullow\u2019s entire Gabonese portfolio of assets, representing c.10 kbopd of 2025 production guidance and c.36 million barrels of 2P reserves. Conditions precedent for the completion of the Transaction include all necessary approvals (including from government ministries), CEMAC Competition Commission approval and Tullow\u2019s processing of the 2024 dividend in compliance with Gabonese requirements. This is a non adjusting event as at 31 December 2024 as defined by IAS 10 Events after the Reporting Period. There have not been any other events since 31 December 2024 that have resulted in a material impact on the year end results. ", "dimensions": { "concept": "ifrs-full:DisclosureOfNonadjustingEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-401": { "value": "
Note 27. Cash flow statement reconciliations
2024 2023
Purchases of intangible exploration and evaluation assets $m $m
Additions to intangible exploration and evaluation assets
34.7
25.4
Associated cash flows
Purchases of intangible exploration and evaluation assets
(27.8)
(30.2)
Non-cash movements/presented in other cash flow lines
Movement in working capital
(6.9)
4.8
2024 2023
Purchases of property, plant and equipment $m $m
Additions to property, plant and equipment
156.1
499.5
Associated cash flows
Purchases of property, plant and equipment
1
(204.8)
(262.3)
Non-cash movements/presented in other cash flow lines
Decommissioning asset revisions
39.3
(47.8)
Right-of-use asset additions
(1.4)
(81.1)
Movement in working capital
10.8
(108.3)
1. Included in purchases of property, plant and equipment is $8.1 million in relation to the asset swap transaction in Gabon. See note 14.
2024 2023 2022 2024 2023
Movement in borrowings $m $m $m Movement Movement
Borrowings
1,975.8
2,084.6
2,472.8
(108.8)
(388.2)
Associated cash flows
Debt arrangement fees
\u2013
(5.0)
Repayment of borrowings
(100.0)
(432.2)
Drawdown of borrowings
\u2013
129.7
Non-cash movements/presented in other cash flow lines
Gain on bond buyback
\u2013
(86.0)
Amortisation of arrangement fees and accrued interest
(8.8)
5.3
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-402": { "value": "
Note 28. Dividends
In 2024, the Board recommended that no interim or final dividend would be paid.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-403": { "value": "
Note 29. Tullow Oil plc subsidiaries
As at 31 December 2024
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 Limited
1
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
WA6
000, Australia
Tullow Chinguetti Production Pty
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
Limited
WA6
000, Australia
Tullow Petroleum (Mauritania) Pty
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
Limited
WA6
000, Australia
Tullow Uganda Operations Pty LimitedAustralia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
WA6
000, Australia
Eagle Drill Limited
2
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
Nemours Chambers, Tortola, British Virgin Islands
DWT-T Company
3
Cayman Islands
Indirect
PO
Box
323
22, 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
4
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
5
England and Wales
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Oil 101 Limited
6
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 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. Dissolved on 6 May 2024.
2. Dissolved on 17 January 2025.
3. Dissolved on 10 September 2024.
4. Dissolved on 30 January 2024.
5. Dissolved on 31 December 2024.
6. Dissolved on 30 January 2024.
Country of Direct or
Company name incorporation
indirect
Address of registered office
Tullow Oil (Mauritania) Limited
Guernsey
Indirect
Plaza, House, Third Floor, Elizabeth Avenue,
St Peter Port GY1 3HB, Guernsey
Tullow Oil Limited
Ireland
Direct
11 Adelaide Road, Dublin 2, Dublin, Ireland
Tullow Congo Limited
7
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 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
8
Jersey
Direct
44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Oil International Limited
Jersey
Indirect
44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Hardman Holdings BV
9
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
10
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Zambia BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Energy Africa Bredasdorp (Pty) Limited
11
South Africa
Indirect
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
Tullow South Africa (Pty) Limited
12
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
7. Dissolved on 22 April 2024.
8. Dissolved on 17 June 2024.
9. Dissolved on 15 October 2024.
10. Dissolved on 6 December 2024.
11. Dissolved on 4 July 2024.
12. Dissolved on 5 November 2024.
", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-471": { "value": "Note 29. Tullow Oil plc subsidiaries As at 31 December 2024 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 Limited
1
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
WA6
000, Australia
Tullow Chinguetti Production Pty
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
Limited
WA6
000, Australia
Tullow Petroleum (Mauritania) Pty
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
Limited
WA6
000, Australia
Tullow Uganda Operations Pty LimitedAustralia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
WA6
000, Australia
Eagle Drill Limited
2
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
Nemours Chambers, Tortola, British Virgin Islands
DWT-T Company
3
Cayman Islands
Indirect
PO
Box
323
22, 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
4
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
5
England and Wales
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Oil 101 Limited
6
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 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. Dissolved on 6 May 2024. 2. Dissolved on 17 January 2025. 3. Dissolved on 10 September 2024. 4. Dissolved on 30 January 2024. 5. Dissolved on 31 December 2024. 6. Dissolved on 30 January 2024.
Country of Direct or
Company name incorporation
indirect
Address of registered office
Tullow Oil (Mauritania) Limited
Guernsey
Indirect
Plaza, House, Third Floor, Elizabeth Avenue,
St Peter Port GY1 3HB, Guernsey
Tullow Oil Limited
Ireland
Direct
11 Adelaide Road, Dublin 2, Dublin, Ireland
Tullow Congo Limited
7
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 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
8
Jersey
Direct
44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Oil International Limited
Jersey
Indirect
44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Hardman Holdings BV
9
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
10
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Zambia BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Energy Africa Bredasdorp (Pty) Limited
11
South Africa
Indirect
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
Tullow South Africa (Pty) Limited
12
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
7. Dissolved on 22 April 2024. 8. Dissolved on 17 June 2024. 9. Dissolved on 15 October 2024. 10. Dissolved on 6 December 2024. 11. Dissolved on 4 July 2024. 12. Dissolved on 5 November 2024.", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-464": { "value": "Note 29. Tullow Oil plc subsidiaries As at 31 December 2024 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 Limited
1
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
WA6
000, Australia
Tullow Chinguetti Production Pty
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
Limited
WA6
000, Australia
Tullow Petroleum (Mauritania) Pty
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
Limited
WA6
000, Australia
Tullow Uganda Operations Pty LimitedAustralia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
WA6
000, Australia
Eagle Drill Limited
2
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
Nemours Chambers, Tortola, British Virgin Islands
DWT-T Company
3
Cayman Islands
Indirect
PO
Box
323
22, 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
4
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
5
England and Wales
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Oil 101 Limited
6
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 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. Dissolved on 6 May 2024. 2. Dissolved on 17 January 2025. 3. Dissolved on 10 September 2024. 4. Dissolved on 30 January 2024. 5. Dissolved on 31 December 2024. 6. Dissolved on 30 January 2024.
Country of Direct or
Company name incorporation
indirect
Address of registered office
Tullow Oil (Mauritania) Limited
Guernsey
Indirect
Plaza, House, Third Floor, Elizabeth Avenue,
St Peter Port GY1 3HB, Guernsey
Tullow Oil Limited
Ireland
Direct
11 Adelaide Road, Dublin 2, Dublin, Ireland
Tullow Congo Limited
7
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 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
8
Jersey
Direct
44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Oil International Limited
Jersey
Indirect
44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Hardman Holdings BV
9
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
10
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Zambia BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Energy Africa Bredasdorp (Pty) Limited
11
South Africa
Indirect
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
Tullow South Africa (Pty) Limited
12
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
7. Dissolved on 22 April 2024. 8. Dissolved on 17 June 2024. 9. Dissolved on 15 October 2024. 10. Dissolved on 6 December 2024. 11. Dissolved on 4 July 2024. 12. Dissolved on 5 November 2024.", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-444": { "value": "Note 29. Tullow Oil plc subsidiaries As at 31 December 2024 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 Limited
1
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
WA6
000, Australia
Tullow Chinguetti Production Pty
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
Limited
WA6
000, Australia
Tullow Petroleum (Mauritania) Pty
Australia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
Limited
WA6
000, Australia
Tullow Uganda Operations Pty LimitedAustralia
Indirect
Level 9, The Quadrant, 1 William Street, Perth
WA6
000, Australia
Eagle Drill Limited
2
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
Nemours Chambers, Tortola, British Virgin Islands
DWT-T Company
3
Cayman Islands
Indirect
PO
Box
323
22, 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
4
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
5
England and Wales
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Oil 101 Limited
6
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 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. Dissolved on 6 May 2024. 2. Dissolved on 17 January 2025. 3. Dissolved on 10 September 2024. 4. Dissolved on 30 January 2024. 5. Dissolved on 31 December 2024. 6. Dissolved on 30 January 2024.
Country of Direct or
Company name incorporation
indirect
Address of registered office
Tullow Oil (Mauritania) Limited
Guernsey
Indirect
Plaza, House, Third Floor, Elizabeth Avenue,
St Peter Port GY1 3HB, Guernsey
Tullow Oil Limited
Ireland
Direct
11 Adelaide Road, Dublin 2, Dublin, Ireland
Tullow Congo Limited
7
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 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
8
Jersey
Direct
44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Oil International Limited
Jersey
Indirect
44 Esplanade, St Helier JE4 9WG, Jersey
Tullow Hardman Holdings BV
9
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
10
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Tullow Zambia BV
Netherlands
Indirect
9 Chiswick Park, 566 Chiswick High Road,
London W4 5XT, United Kingdom
Energy Africa Bredasdorp (Pty) Limited
11
South Africa
Indirect
Maitland House 1 \u2013 River Park, Gloucester Road,
Mowbray, Western Cape 7700, South Africa
Tullow South Africa (Pty) Limited
12
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
7. Dissolved on 22 April 2024. 8. Dissolved on 17 June 2024. 9. Dissolved on 15 October 2024. 10. Dissolved on 6 December 2024. 11. Dissolved on 4 July 2024. 12. Dissolved on 5 November 2024.", "dimensions": { "concept": "ifrs-full:DisclosureOfCompositionOfGroupExplanatory", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-404": { "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
1
Jubilee, Mahogany, Teak
38.98%
Tullow
Kosmos, KEGIN, GNPC, Jubilee Oil
Holdings, Petro SA
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-Operate d
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), PetroEnergy
DE82
DE8
2,393
40.00%
Perenco
Ebouri
Ebouri
15
7.50%
Vaalco
Addax (Sinopec), PetroEnergy
Echira
Echira
76
40.00%
Perenco
Gabon Oil Company
Etame
Etame, North Tchibala
49
7.50%
Vaalco
Addax (Sinopec), 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
Kenya
Area Tullow
Licence
Fields
sq km
interest
Operator
Other partners
Kenya
Block 10BA
2
11,569
100.00%
Tullow
Block 10BB
2
Amosing, Ngamia
6,172
100.00%
Tullow
Block 12B
6,200
100.00%
Tullow
Block 13T
2
Ekales, Twiga
4,719
100.00%
Tullow
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
2. Subject to Government of Kenya consent (refer to note 8 above).
", "dimensions": { "concept": "tullowoilplc:DisclosureOfLicenseInterests", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-6": { "value": "Tullow Oil plc", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-345": { "value": "plc", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-7": { "value": "Tullow Oil plc", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:2138003EYHWO75RKS857", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } } } }