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1. General information
Ithaca Energy plc (the Group or Ithaca Energy), is a public Company limited by shares incorporated and domiciled in the UK and is a Group involved in the development and production of oil and gas in the North Sea.
The Group\u2019s registered office is 33 Cavendish Square, London, W1G 0PP, United Kingdom.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-9": { "value": "Ithaca Energy plc", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-11": { "value": "Company limited by shares", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-10": { "value": "UK", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-378": { "value": "UK", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-12": { "value": "development and production of oil and gas in the North Sea.", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-13": { "value": "33 Cavendish Square, London, W1G 0PP, United Kingdom.", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-382": { "value": "
2. Basis of preparation
The consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standards (IAS) and in conformity with the requirements of the Companies Act 2006.
The consolidated financial statements are presented in US Dollars as this is the functional currency of the business. All values are rounded to the nearest thousand ($\u2019000), except when otherwise indicated.
The principal accounting policies applied in the preparation of the financial statements are set out below. These policies have been consistently applied to all the periods presented.
Prior period adjustments
During the preparation of the Q1 2024 condensed consolidated financial statements, management identified an incorrect calculation in the 2023 deferred EPL tax charge related to the impairment charge of $229.5 million recorded in
Q4 of 2023. As a result of this incorrect calculation, the tax charge and the profit for the year to 31 December 2023 were overstated and understated, respectively by $76.9 million, and the net deferred tax asset and retained earnings
were both understated by $76.9 million at 31 December 2023.
Details of amounts as previously stated, prior period adjustments and amounts as restated were:
Statement of financial position as at 31 December 2023: As previously stated
Prior period
adjustment As restated
Deferred tax assets ($\u2019000) 627,738 76,919 704,657
Retained earnings ($\u2019000) 1,895,128 76,919 1,972,047
Net assets ($\u2019000) 2,444,426 76,919 2,521,345
Statement of profit or loss for the year to 31 December 2023: As previously stated
Prior period
adjustment As restated
Income tax charge ($\u2019000) (86,392) 76,919 (9,473)
Profit for the year ($\u2019000) 215,635 76,919 292,554
Basic EPS (cents) 21.4 7.7 29.1
Diluted EPS (cents) 21.2 7.5 28.7
", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-437": { "value": "The consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standards (IAS) and in conformity with the requirements of the Companies Act 2006.", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-438": { "value": "The consolidated financial statements are presented in US Dollars as this is the functional currency of the business. All values are rounded to the nearest thousand ($\u2019000), except when otherwise indicated. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-379": { "value": "
3. Material accounting policies, judgements and estimation uncertainty
Basis of measurement
The consolidated financial statements have been prepared on a going concern basis using the historical cost convention, except for the revaluation of certain financial assets and financial liabilities, under International Financial Reporting
Standards (IFRS), to fair value, including derivative instruments. Historical cost is generally based on the fair value consideration given in exchange for the assets and liabilities.
Going concern
Management closely monitor the funding position of the Group, including monitoring compliance with covenants and available facilities to ensure sufficient headroom is maintained to fund operations. Management have considered
a number of risks applicable to the Group that may have an impact on the Group\u2019s ability to continue as a going concern. Short-term and long-term cash forecasts are prepared on a weekly and quarterly basis respectively, along with any
related sensitivity analysis. This allows proactive management of any business risk including, liquidity risk.
The Directors consider the preparation of the financial statements on a going concern basis to be appropriate. This is due to the following key factors:
\u2022 Continuing robust commodity price backdrop and a well-hedged portfolio over the next 12 months;
\u2022 Reserves Based Lending (RBL) liquidity headroom of $850 million ($150 million drawn versus $1,000 million available), plus $383 million of cash as at 14 March 2025; and
\u2022 Robust operational performance and a well-diversified portfolio.
Cash flow forecast \u2013 base case assumptions:
2025
H1 2026
Average oil price
$/bbl
71
68
Average gas price
p/th
107
96
Average hedged oil price (including floor price for zero cost collars)
$/bbl
75
70
Average hedged gas price (including floor price for zero cost collars)
p/th
91
89
The oil and gas price assumptions used in the going concern and viability assessments represent management's current best estimates at the date of approval of the Annual Report and Accounts, as supported by data from third-party
analysis, of future commodity prices whereas the commodity prices used in impairment testing (see note 19) are based on market conditions at 31 December 2024.
Owing to the ongoing fluctuations in commodity demand and price volatility, management prepared sensitivity analyses to the forecasts and applied a number of plausible downside scenarios, including decreases in production of 10%,
reduced sales prices of 20% and increases in operating and capital expenditures of 10%. Management aggregated these scenarios to create a reasonable combined worst-case scenario. The sensitivity analysis showed that, without any
consideration of the mitigation strategies within management\u2019s control, there was no reasonably possible scenario that would result in the business being unable to meet its liabilities as they fell due. In addition, reverse stress tests have
been performed reflecting further reductions in commodity prices, prior to any mitigating actions, to determine at what levels prices would have to reach such that there is no liquidity headroom left. The stress tests demonstrated that
the likelihood of the fall in prices required to cause a liquidity issue is considered sufficiently remote in the context of the mitigation strategies available to management. The mitigation strategies within the control of management include
a reduction in uncommitted capital expenditure and variable opex savings in the low production scenario. The analysis demonstrated that the Group would still continue to comply with financial covenants and have sufficient liquidity
throughout the period to 30 June 2026 to continue trading.
Based on their assessment of the Group\u2019s financial position in the period to 30 June 2026, the Directors believe that the Group will be able to continue in operational existence for the foreseeable future. Accordingly, they continue to
adopt the going concern basis of accounting in preparing the financial statements.
Basis of consolidation
The consolidated financial statements of the Group includes the financial information of Ithaca Energy plc and all wholly-owned subsidiaries as listed per note 32. All intergroup transactions and balances have been eliminated on consolidation.
Subsidiaries are all entities over which the Group has control. The plc controls an entity when the Group is exposed to or has rights to variable returns from its investments with the entity and has the ability to affect those returns
through its power over the investee. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated on the date that control ceases.
Impact of climate change on the financial statements and related notes
Judgements and estimates made in assessing the impact of climate change and the energy transition
Climate change and the transition to a lower-carbon system were considered in preparing the consolidated financial statements. These may have the potential for significant impacts on the carrying values of the Group\u2019s assets and
liabilities discussed below as well as on assets and liabilities that may be reflected in the future. There is also the potential for significant impact on future cash flows. There is generally a high level of uncertainty about the speed and
magnitude of impacts of climate change which, together with limited historical data, provides significant challenges in the preparation of forecasts and financial plans with a wide range of potential future outcomes.
The Group\u2019s ambition is to have one of the lowest carbon emission portfolios in the UK North Sea and to achieve Net Zero (whereby the amount of CO
2
added by the Group\u2019s activities is no greater than the amount taken away), on a
net equity basis (by applying the Group\u2019s working interest in each respective asset to the total emissions of that asset), and in respect of Scope 1 and 2 emissions, by 2040, ten years ahead of the North Sea Transition Deal commitment.
This will be achieved by optimising the Group\u2019s current portfolio in the short term and fundamentally transitioning the Group\u2019s portfolio over the medium to long term whilst maintaining forecast levels of production. Initiatives include,
but are not limited to, operational improvements, offshore electrification, acquisition and investment into lower carbon intensity assets and the eventual cessation of production of mature fields which have higher carbon intensity. In
addition, the Eni UK Business Combination has given the Group a portfolio with a relatively lower carbon footprint. Where the Group cannot reduce Scope 1 and Scope 2 emissions, Ithaca Energy will invest in carbon offsets to achieve
the Group\u2019s goal of Net Zero. All new economic investment decisions include estimated costs of the energy transition based on existing technology and estimated costs of carbon and these opportunities are assessed on their climate
impact potential and alignment with Ithaca Energy\u2019s Net Zero target, taking into account both greenhouse gas volumes and emissions intensity.
Specific considerations of the potential impacts of climate change on significant judgements and estimates used in the consolidated financial statements are considered below. The items outlined below are likely to manifest themselves
over a number of years and are, therefore, not generally considered to represent 'key sources of estimation uncertainty' as required by IAS 1 (being those which could have a material impact on the Group\u2019s results in the
12 months following the date of the consolidated statement of financial position) which are separately disclosed later in this note.
Impairment of goodwill and property, plant and equipment
The energy transition has the potential to significantly impact future commodity and carbon prices in that as the UK and global energy system decarbonises, reduced demand for oil and gas products in favour of low carbon alternatives
could cause oil and gas prices to fall which would, in turn, affect the recoverable amount of goodwill and property, plant and equipment. In the current period management\u2019s estimate of the long-term commodity price assumptions are,
in nominal terms from 2031, $83/bbl for Brent Crude and 87p/therm for UK NBP gas. Further details of climate change, including a sensitivity in this area are provided in note 19.
Recoverable values used for impairment testing for all cash-generating units (CGUs) include the estimated cost of UK carbon emissions allowances in real terms for CO
2
e of \u00a350/tonne, \u00a370/tonne and \u00a380/tonne for 2025,2026 and
2027 respectively. The recoverable value of CGU\u2019s may be impacted by future carbon pricing legislation changes, which could increase operating costs through higher emissions allowances or the introduction of other carbon pricing
mechanisms. Electrification of offshore operations for specific assets is planned in line with the Group\u2019s 2040 Net Zero ambitions and where feasible based on existing technology, estimated electrification costs of a market participant
are included within the assessment of the recoverable value of the relevant CGU.
Property, plant and equipment \u2013 depreciation and useful economic lives
The energy transition has the potential to reduce the expected useful economic lives of assets and hence accelerate depreciation charges. Although no changes have been identified or recognised to date, as noted in the Strategic Report
on page 60, it is anticipated that certain higher emission-intensity assets such as FPF-1 and Alba will cease production in the medium term and will be replaced by new lower-emission intensity assets. Management does not currently
expect the useful economic lives of the Group\u2019s reported property, plant and equipment to significantly change solely as a result of the energy transition. However, significant capital expenditure is still required for ongoing projects and
therefore, the useful lives of future capital expenditure may be different.
Intangible assets \u2013 exploration and evaluation assets
The impacts of climate change and the energy transition may affect the viability of exploration prospects, for example due to the impact on future commodity and carbon prices (as explained above) or due to the increased risk
of regulatory challenge as prospects progress through to development. The recoverability of the existing intangibles was considered during 2024, however, no significant write-offs were identified as a result of climate change
considerations. Viability of these assets will continue to be assessed on a regular basis.
Decommissioning provisions
Most of the Group\u2019s existing decommissioning obligations are estimated to be completed over the course of the next 20 years. The impacts of climate change and the energy transition may bring forward the expected timing
of decommissioning activity, increasing the present value of the associated decommissioning provisions. The potential impact of a reasonably possible acceleration of estimated decommissioning dates, which considers the potential
impact of the energy transition, is considered to be two years. The impact of such an acceleration of cessation of production across the Group\u2019s entire producing portfolio would result in an increase in the decommissioning provision of
approximately $93 million (2023: $69 million). The risk in this area may increase if key assets within the Group\u2019s existing exploration, appraisal and development portfolio proceed to the production stage, as this is likely to significantly
extend the life of the Group\u2019s portfolio, in some cases to 2050 or beyond.
While the pace of the transition to a lower-carbon economy is uncertain, oil and gas demand is expected to remain a key element of the energy mix for many years based on stated policies, commitments and announced pledges to
reduce emissions. Therefore, given the estimated useful lives of the Group\u2019s oil and gas portfolio, a material adverse change is not anticipated to the carrying value of the Group\u2019s assets and liabilities in the short-term as a result of
climate change and the transition to a lower-carbon economy.
Business combinations
Business combinations are accounted for using the acquisition method. The cost of a business combination is measured as the fair value of the consideration given for the assets acquired, equity instruments issued and liabilities incurred
or assumed at the date of completion of the business combination. Transaction costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a
business combination are measured initially at their fair values at the date of the business combination. The excess of the cost of the business combination over the fair value of the Group\u2019s share of the identifiable net assets acquired is
recorded as goodwill. If the cost of the business combination is less than the Group\u2019s share of the net assets acquired, the difference is recognised directly in the consolidated statement of profit or loss as a gain on bargain purchase.
Goodwill Capitalisation Goodwill is initially recognised and measured as set out above. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Impairment Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU or Group of CGUs to which the goodwill relates. If the recoverable amount of a CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of goodwill allocated to the unit and then to the other assets of the unit pro-rata based on the carrying amount of each asset in the unit. Any impairment loss is recognised in the consolidated statement of profit or loss. Impairment losses relating to goodwill cannot be reversed in future periods. The CGU for the purposes of the goodwill test is the North Sea, i.e. the entire Group portfolio of oil and gas assets which is consistent with the operating segment view of the business. Interest in joint ventures Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Group\u2019s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its proportionate share of assets held jointly), its liabilities (including its proportionate share of liabilities incurred jointly), its revenue from the sale of its proportionate share of the output arising from the joint operation and its expenses (including its proportionate share of any expenses incurred jointly). Revenue The sale of crude oil, gas or condensate represents a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue is accordingly recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. Revenue is recognised at a point in time and is measured based on the consideration to which the Group expects to be entitled in a contract with a customer and excludes amounts collected for third parties. Details of hedging gains and losses presented in revenue are discussed in the hedging accounting policy set out below. Tariff income is recognised as the underlying commodity is shipped through the pipeline network based on established tariff rates. Foreign currency translation Items included in these consolidated financial statements are measured using the currency of the primary economic environment in which the Group and its subsidiaries operate (the functional currency). The consolidated financial statements are presented in US Dollars, which is the Group\u2019s presentation currency as well as the functional currency of the Parent Company and each of its subsidiaries. In preparing the financial statements of the parent and its subsidiaries, transactions in currencies other than the entity\u2019s functional currency (foreign currencies) are recognised at the rates of exchange prevailing on the dates of the transactions. At each reporting date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of profit or loss. Exchange differences are recognised in profit or loss in the period in which they arise except for: \u2022 Exchange differences on foreign currency borrowings relating to assets under construction for future productive use, which are included in the cost of those assets when they are regarded as an adjustment to interest costs on those foreign currency borrowings; \u2022 Exchange differences on transactions entered into to hedge certain foreign currency risks (see below under financial instruments/hedge accounting). Dividend distribution Dividend distribution to the Company\u2019s shareholders is recognised as a liability in the Company\u2019s financial statements in the period in which the dividends are approved by the Company\u2019s shareholders. Details of dividends paid and declared are set out in note 34 .
Financial instruments
All financial instruments are initially recognised at fair value on the statement of financial position. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.
The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another
entity. The difference between the carrying amount of the financial asset derecognised and the consideration received/receivable is recognised in profit or loss.
The Group derecognises financial liabilities when, and only when, the Group\u2019s obligations are discharged, cancelled or have expired. The Group considers whether refinancing arrangements represent settlement of the existing debt and
issuance of a new debt or an exchange or modification of the previous debt. In making this assessment, the Group considers, amongst other factors, pre-existing early redemption options in the original agreement, the group of lenders
to which the new debt is offered and any preferential terms or rights given to the original lenders. Where the new debt is considered to represent an arms-length market offering, the issuance of the new debt is viewed as separate from
the extinguishment of the old debt and is treated as the derecognition of the original liability and the recognition of a new liability. The difference between the carrying amount of the financial liability derecognised and the consideration
paid/payable (excluding consideration payable for fees incurred on the new liability or accrued interest) is recognised in profit or loss.
IFRS 9 classifications
Cash and cash equivalents are classified at amortised cost which equates to its fair value. Accounts receivable and long-term receivables are classified and carried at amortised cost less expected credit losses. These items have a business
model of held to collect and the terms of the financial instrument meet the classification of solely payments of interest on principle outstanding. Accounts payable, accrued liabilities, certain other long-term liabilities, and borrowings
are classified as other financial liabilities and carried at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium. Contingent consideration is measured
at fair value though profit or loss. Although the Group does not intend to trade its derivative financial instruments, they are required to be carried at fair value with the treatment of fair value movements explained further below.
Transaction costs, presentation and cash flows
Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability (excluding the costs directly attributable to the new loan commitment facilities) have been included in the carrying value of the
related financial asset or liability and are amortised to consolidated net earnings over the life of the financial instrument using the effective interest method.
Directly attributable fees paid on the establishment of new loan commitment facilities are capitalised to the extent that it is probable that some or all of the facility will be drawn down. These costs are recognised on a systematic basis
over the period the Group is able to draw down. Fees that are calculated based on the usage of the facility (including letter of credit fees) are expensed as incurred.
Borrowings are presented as non-current when they are not due to be settled within twelve months after the reporting period or where the Group has the right at the end of the reporting period to defer settlement for at least twelve
months after the reporting period.
Cash flows relating to refinancing are presented in the Statement of Cash Flows on a net basis where that reflects the actual cash flows received by the Group. The refinancing proceeds in the Statement of Cash Flows are stated
after deduction of fees which were deducted from the amount paid to the Group. Other fees paid on refinancing are presented as a separate line item within financing activities or within Interest and charges paid in the Statement
of Cash Flows.
Impairment of financial assets
For trade receivables and accrued income, the Group applies a simplified approach in calculating expected credit losses (ECLs). Therefore, the Group does not track changes in credit risk, but instead, recognises any material loss
allowance based on lifetime ECLs at each reporting date. For all other financial assets, the Group measures the loss allowance using 12-month expected credit losses unless there was a significant increase in credit risk since initial
recognition in which case the loss allowance is measured using lifetime expected credit losses.
In making this assessment whether the credit risk increased significantly since initial recognition, the Group considers both quantitative and qualitative information that is reasonable and supportable, including historical experience
and forward-looking information that is available without undue cost or effort. The Group considers that the credit risk increased significantly since initial recognition when the credit rating changes, the debtor has significant financial
difficulty or if there was a breach of contract. For balances that are beyond 30 days overdue it is presumed to be an indicator of a significant increase in credit risk.
The Group considers a financial asset in default when contractual payments are 90 days past due. However, in certain cases, the Group may also consider a financial asset to be in default when internal or external information indicates
that the Group is unlikely to receive the outstanding contractual amounts in full before taking into account any credit enhancements held by the Group.
A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. Financial assets written off may still be subject to enforcement activities under the Group\u2019s recovery procedures,
taking into account legal advice where appropriate. Any recoveries made are recognised in profit or loss.
Derivative financial instruments
The Group enters into a variety of derivative financial instruments to manage its exposure to commodity risks, interest rate and foreign exchange rate risks. These instruments include: commodity swaps, collars and options; foreign
exchange forward contracts and collars; and interest rate swaps. Further details of derivative financial instruments are disclosed in notes 30 and 31.
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 on remeasurement of derivatives
is recognised in profit or loss immediately unless the derivative is designated in a hedge relationship 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.
A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a financial liability. Derivatives are not offset in the financial statements unless the Group has both
a legally enforceable right and intention to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than 12 months and it is not due to be realised or settled
within 12 months. Other derivatives maturing in less than 12 months and expected to be realised or settled in less than 12 months are presented as current assets or current liabilities.
Hedge accounting
The Group designates certain derivatives as hedging instruments in respect of commodity risks in cash flow hedges.
At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge
transactions. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is highly effective in offsetting changes in fair values or cash flows of the hedged item
attributable to the hedged risk.
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 hedging instrument, 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 cost of hedging 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 cost of hedging reserve is reclassified to profit or loss on a rational basis \u2013 the Group applies straight-line amortisation. Those reclassified amounts are recognised in profit or loss in the same
line as the hedged item. If the Group expects that some or all of the loss accumulated in the cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.
The effective portion of changes in the fair value of derivatives and other qualifying hedging instruments that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated under the
heading of cash flow hedge reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss, and is
included in the 'other gains and losses' line item.
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 revenue line as the recognised hedged
item. However, when the hedged forecast transaction results in the recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognised in other comprehensive income and accumulated in equity are
removed from equity and included in the initial measurement of the cost of the non-financial asset or non-financial liability. This transfer does not affect other comprehensive income. Furthermore, if the Group expects that some or all
of the loss accumulated in the cash flow hedge reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.
The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is
sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified
to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in the cash flow hedge reserve is reclassified immediately to profit or loss.
If a hedge of a transaction-related item is discontinued part way through the life of the hedge (e.g. due to early termination of the swap, hedging resets), but the hedged item is still expected to occur, the amounts deferred in equity
would remain in equity until the earlier of: (i) the hedged transaction occurring; or (ii) expectation that the amount deferred in equity will not be recovered in the future periods.
Note 30 and note 31 set out details of the fair values of the derivative instruments used for hedging purposes, and movements in the cash flow hedge reserve and cost of hedging reserve in equity are detailed in note 30.
Contingent and deferred consideration Contingent consideration in relation to a business combination or asset acquisition is accounted for as a financial liability and measured at fair value at the date of acquisition with any subsequent remeasurements recognised in profit or loss in accordance with IFRS 9. These fair values are generally based on risk-adjusted future cash flows discounted using appropriate discount rates. Changes in fair value of the contingent consideration that qualify as measurement period adjustments are adjusted retrospectively, with corresponding adjustments against goodwill. Measurement period adjustments are adjustments that arise from additional information obtained during the 'measurement period' (which cannot exceed one year from the date of the business combination) about facts and circumstances that existed at the date of the business combination. The subsequent accounting for changes in the fair value of the contingent consideration that do not qualify as measurement period adjustments depends on how the contingent consideration is classified. Contingent consideration that is classified as equity is not remeasured at subsequent reporting dates and its subsequent settlement is accounted for within equity. Other contingent consideration is remeasured to fair value at subsequent reporting dates with changes in fair value recognised in profit or loss. Deferred consideration is measured at amortised cost because the amount payable in the future is fixed. Settlement of contingent consideration is recorded as investing outflows in the cash flow statement to the extent that cumulative amounts paid do not exceed the amount recognised at the date of acquisition, with any excess recorded as an operating cash outflow. Settlement of deferred consideration is recorded as either an investing or financing outflow in the cash flow statement, depending on the substance of the arrangement at inception. Key considerations in forming this judgement will include the extent of inferred financing costs included in the overall consideration arrangements at acquisition, the period of time over which the payments are made, the rationale for agreeing to defer elements of the consideration and the general level of funding resources available to the Group at the time of acquisition. Cash and cash equivalents For the purpose of the statement of cash flows, cash and cash equivalents include investments with an original maturity of three months or less. In the statement of financial position, cash and bank balances comprise cash (i.e. cash on hand and demand deposits) and cash equivalents. Cash equivalents are short-term (generally with original maturity of three months or less), highly-liquid investments that are readily convertible to a known amount of cash and which are subject to an insignificant risk of changes in value. Cash equivalents are held for the purpose of meeting short-term cash commitments rather than for investment or other purposes. Inventories \u2013 hydrocarbon and materials Inventories of materials are stated at the lower of cost and net realisable value. Cost comprises direct materials and, where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition. Cost is determined on the first-in, first-out method. Current hydrocarbon inventories are stated at net realisable value, which is based on estimated selling price less any further costs expected to be incurred to completion and disposal/sale. Non-current oil and gas inventories are stated at historic cost. Provision is made for obsolete, slow-moving and defective items where appropriate. Lifting or offtake arrangements Lifting or offtake arrangements for oil and gas produced in certain of the Group\u2019s oil and gas properties 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 volume sold is an \u2018underlift\u2019 included within inventories, or an \u2018overlift\u2019 included within trade and other payables in the statement of financial position. Both are stated at net realisable value using an observable year-end oil or gas market price. Movements during an accounting period are adjusted through cost of sales in the consolidated statement of profit or loss. Exploration and evaluation assets Oil and gas expenditure \u2013 exploration and evaluation (E&E) assets Geological and geophysical costs and costs incurred pre-licence are expensed as incurred. Costs directly associated with an exploration well are initially capitalised as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, freight costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is, the efforts are not successful, then the costs are expensed. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalised as an intangible asset. Upon external approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is first assessed for impairment and, if required, an impairment loss is recognised. The remaining balance is then transferred to development and production (D&P) assets. If development is not approved and no further activity is expected to occur, then the costs are expensed. The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required before production could begin and where the economic viability of that major capital expenditure depends on the successful completion of further exploitation or appraisal work in the area remain capitalised on the balance sheet as long as such work is under way or firmly planned. Property, plant and equipment Oil and gas expenditure \u2013 D&P assets Capitalisation Costs of bringing a field into production, including the cost of facilities, wells and subsea equipment, direct costs including staff costs together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset. Depreciation All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset generally on a field-by-field basis. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset. Non-oil and natural gas operations Non-oil and gas assets are initially recorded at cost and depreciated over their estimated useful lives on a straight-line basis as follows: Buildings 10 years Computer and office equipment 3 years Furniture and fittings 5 years Impairment For impairment review purposes the Group\u2019s oil and gas assets are aggregated into CGUs typically on a field-by-field basis for development and production assets in accordance with IAS 36, and on a North Sea segment basis for exploration and evaluation assets in accordance with IFRS 6. A review is carried out at each reporting date for any indicators that the carrying value of the Group\u2019s assets may be impaired. Such reviews are carried out on a field-by-field basis for both development and production assets and exploration and evaluation assets. For assets where there are such indicators, an impairment test is carried out on the CGU. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to the recoverable amount. The resulting impairment losses are written off to the consolidated statement of profit or loss. Previously impaired assets (excluding goodwill) are reviewed for possible reversal of previous impairment at each reporting date. The maximum possible reversal is capped at the net book value had the asset not been impaired in the past. Where an exploration and evaluation licence is relinquished, amounts capitalised in respect of the licence are written off to profit or loss in the period in which the licence is relinquished. 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 borrowing costs are expensed as incurred. Borrowing costs directly attributable to E&E assets are not capitalised and are expensed directly to profit or loss when incurred. Decommissioning liabilities The Group records the present value of legal obligations associated with the retirement of long-term tangible assets, such as producing well sites and processing plants, in the period in which they are incurred with a corresponding increase in the carrying amount of the related long-term asset. Liabilities for decommissioning are recognised when the Group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and restore the site on which it is located, and when a reliable estimate can be made. Where the obligation exists for a new facility or well, such as oil and gas production or transportation facilities, the obligation generally arises when the asset is installed or the ground/environment is disturbed at the field location. In subsequent periods, the asset is adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. Changes in decommissioning cost estimates for assets that have either been fully written off or have ceased production are expensed as impairment charges in the period the change occurs. The carrying amounts of the associated decommissioning assets are depleted using the unit of production method in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred. The unwinding of discount in the net present value of the total expected cost is treated as an interest expense. Changes in the estimates are reflected prospectively over the remaining life of the field. Where some or all of the expenditure required to settle a provision is expected to be reimbursed by another party, a reimbursement asset is recognised when, and only when, it is virtually certain that reimbursement will be received if the entity settles the obligation. The amount recognised for the reimbursement may not exceed the amount of the provision. Taxation Current tax Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted by the reporting date. Taxable profit differs from net profit, as reported in the consolidated statement of profit or loss, because it excludes items of income or expense that are taxable or deductible in other accounting periods and it further excludes items of income or expenses that are never taxable or deductible. Deferred tax Deferred tax is recognised using the liability method, providing for temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax is measured at the tax rates that are expected to be applied to the temporary differences when they are forecast to reverse, based on the laws that have been enacted or substantively enacted at each balance sheet date. Details of changes in EPL and other tax matters are set out in note 28. Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill and deferred tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred tax assets are recognised only to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each balance sheet date and all available evidence is considered in evaluating the recoverability of these deferred tax assets. Deferred tax assets and liabilities are offset where there is a legally enforceable right to offset current tax assets and liabilities relating to taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis. Deferred Petroleum Revenue Tax (PRT) assets are recognised where PRT relief on future decommissioning costs is probable. Leases The Group assesses at contract inception all arrangements to determine whether it is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Group is not a lessor in any transactions, it is only a lessee. The Group recognises a right-of-use asset and a corresponding lease liability with respect to all lease arrangements in which it is the lessee. The Group has elected to apply Paragraph 6 of IFRS 16 to short-term leases (defined as leases with a lease term of 12 months or less) and leases of low-value assets (such as tablets and personal computers, small items of office furniture and telephones). Lease payments associated with these leases are expensed over the relevant lease term. Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The right-of-use asset is depreciated over the useful life of the asset. The Group\u2019s right-of-use assets are included in property, plant and equipment (note 15). At the commencement date of the lease, the Group recognises lease liabilities measured at the present value of lease payments to be made over the lease term. In calculating the present value of lease payments, the Group uses its incremental borrowing rate at the lease commencement date because the interest rate implicit in the lease is generally not readily determinable. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments (e.g. changes to future payments resulting from a change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the underlying asset. The Group has elected to apply the practical expedient under IFRS 16.15 to account for lease and associated non-lease components as a single lease component on a class-of-asset basis. Maintenance expenditure Expenditure on major maintenance refits or repairs is capitalised where it enhances the life or performance of an asset above its originally assessed standard of performance, replaces an asset or part of an asset which was separately depreciated and which is then written off, or restores the economic benefits of an asset which has been fully depreciated. All other maintenance expenditure is charged to the statement of profit or loss as incurred. Share-based payments The Group issues equity-settled share-based payments to certain employees. Equity-settled share-based payments are measured at fair value at the date of grant. The fair value is expensed over the vesting term either on a straight-line basis or as specified in the vesting terms, based on the Group\u2019s estimate of shares that will eventually vest and is adjusted for the effects of non-market-based vesting conditions. Fair value is measured by using a Black-Scholes or other appropriate valuation model. The expected life used in the model is adjusted based on management\u2019s best estimate for the effects of non-transferability, exercise restrictions and behavioural considerations. Retirement benefit costs The Group operates a defined contribution pension scheme and payments into this plan are charged as an expense as they fall due. There is no further obligation to pay contributions into the plan once the contributions specified in the plan rules have been paid. Short-term employee benefits A charge or liability is recognised for benefits accruing to employees in respect of salaries, bonuses, annual leave and sick leave in the period the related service is rendered at the undiscounted amount of the benefits expected to be paid for that service. Charges or liabilities recognised in respect of short-term employee benefits are measured at the undiscounted amount of the benefits expected to be paid in exchange for the related service. Non-GAAP measures In measuring the Group\u2019s adjusted operating performance, additional financial measures derived from the reported results have been used by management in order to eliminate factors which distort year-on-year comparisons. The Group\u2019s adjusted performance is used to explain year-on-year changes when the effect of certain items is significant, including impairment charges or reversals, business combination costs, one-off finance charges related to refinancing, the tax effect of these items where applicable and non-cash deferred tax charges on the increase in rate of EPL. Adjusted EBITDAX, adjusted net income, adjusted EPS, unit operating expenditure, leverage ratio, adjusted net debt and certain other reported metrics are non-GAAP measures that are not specifically defined under IFRS or other generally accepted accounting principles. Further details are set out on pages 249 to 252. Changes in accounting pronouncements The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2023 to 31 December 2024. There was no material impact from these or from any of the amendments to existing standards and interpretations which were effective from 1 January 2024. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.
New and revised IFRS Standards in issue but not yet effective
As at 31 December 2024 , the Group had not applied the following new Standards or revisions to existing IFRS Standards, that have been issued but are not yet effective.
IFRS S1 General requirements for disclosure of sustainability related financial information
IFRS S2 Climate related disclosures
Amendments to SASB standards Amendments to the SASB standards to enhance their international applicability
Amendments to IAS 21 Lack of exchangeability
Amendments to IFRS 9 and IFRS 7 Amendments to the classification and measurement of financial instruments
Amendments to IFRS 9 and IFRS 7 Contracts referencing nature-dependent electricity
Annual improvements to IFRS Annual improvements to IFRS Accounting Standards \u2013 volume 11
IFRS 18 Presentation and disclosures in financial statements
IFRS 19 Subsidiaries without public accountability: disclosures
With the exception of IFRS S1, IFRS S2 and IFRS 18, the Group does not expect that the adoption of the new Standards or amendments to existing Standards, listed above, will have a material impact on the consolidated financial
statements of the Group in future periods. The Group is currently assessing the impact of the sustainability and climate Standards which will apply from 1 January 2026 and the Group is also considering the impact of the adoption
of IFRS 18 which will apply from 1 January 2027 onwards.
Critical judgements and key sources of estimation uncertainties
Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within
the next financial year, are discussed below.
Estimates in oil and gas reserves and contingent resources
The Group\u2019s estimates of oil and gas reserves and contingent resources, and the associated production forecasts, are used in the impairment testing of property plant and equipment and goodwill, in the measurement of depletion
and decommissioning provisions, the measurement of certain elements of contingent consideration, the going concern assessment, the viability assessment and in the determination of whether deferred tax assets are recoverable.
The business of the Group is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner. Estimates of oil and gas reserves
and contingent resources require significant judgement. Factors such as the availability of geological and engineering data, reservoir performance data, drilling of new wells and estimates of future oil and gas prices all impact on the
determination of the Group\u2019s estimates of its oil and gas reserves, which could result in different future production profiles affecting prospectively the discounted cash flows used in impairment testing.
The Group\u2019s estimates of reserves and resource volumes used for accounting purposes are built up from historically-matched models for operated assets and principally from operators\u2019 estimates for non-operated assets.
A review process is undertaken to compare the results of the Group\u2019s internal estimates to those of an independent consultant to understand any differences in underlying assumptions to ensure there are no significant
unreconciled differences between the estimates.
For the purposes of depletion and decommissioning estimates, the Group uses proved and probable reserves; and for the purposes of the impairment tests performed and deferred tax asset recoverability, the Group considers the same
proved and probable reserves as well as risked resource volumes. These risking adjustments are reflective of management\u2019s assessment of technical and commercial factors that reflect the value considerations of a market participant.
Changes in estimates of oil and gas reserves and resources resulting in different future production profiles will affect the discounted cash flows used in impairment testing, the anticipated date of decommissioning, the depletion charges
in accordance with the unit of production method and the recoverability of deferred tax assets. The sensitivity of the Group\u2019s impairment tests and deferred tax recoverability assessments to key sources of estimation uncertainty,
including reserves and resources, is discussed below.
Estimates in impairment of oil and gas assets and goodwill Determination of whether the Group\u2019s oil and gas assets (note 15) or goodwill (note 18) have suffered any impairment requires an estimation of the recoverable amount of the CGU to which oil and gas assets and goodwill have been allocated. Projected future cash flows are used to determine a fair value less cost to sell to establish the recoverable amount. Key assumptions and estimates in the impairment models relate to: commodity prices that are based on an external view of forward curve prices that are considered to be a best estimate of what a market participant would use; discount rates which reflect management\u2019s estimate of a market participant post-tax weighted average cost of capital; and oil and gas reserves and resources on a risked basis as described above. Management\u2019s estimates of a market participant\u2019s view of pricing and discount rates are supplied by an independent consultant. The sensitivity of the Group\u2019s carrying amounts to these assumptions is illustrated by the impairments and reversals disclosed in note 19, and by the sensitivity disclosures in note 19. Sensitivity disclosures include, in particular, the impact of a 20% reduction in forecast revenues. Contingent consideration Liabilities for contingent consideration have been recognised on certain business combinations, which are measured at fair value at acquisition and remeasured at fair value through profit and loss at each reporting date. The amounts of contingent consideration ultimately payable depend on several factors, including the progress of certain of the oil and gas properties acquired and the achievement of certain production and commodity price thresholds. Management has estimated the fair value as the aggregate value of each element of the contingent consideration in each case using an appropriate valuation technique, taking into account the likelihood of occurrence of each contingent event and the net present value of the amount potentially payable. Where applicable, risking assumptions applied in the measurement of contingent consideration were consistent with those applied in the fair valuation of the related oil and gas properties. A 20% decrease in the probability of a trigger event occurring and hence a payment being due, with all other assumptions held constant, would result in a decrease in contingent consideration of $84.2 million (2023: $97.1 million). Whereas a 20% increase in probability of a trigger event occurring, with all other assumptions held constant, would result in an increase in contingent consideration of $80.4 million (2023: $84.1 million). Decommissioning provision estimates Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements, technology and price levels, the carrying amounts of decommissioning provisions are reviewed on a regular basis. The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. For operated assets, cost estimates are based on management\u2019s assessment of work programmes (including durations) and supply chain conditions including, amongst other factors, applicable vessel and rig rates and durations. For non-operated assets, cost estimates are arrived at by management\u2019s review of the basis of estimates as provided by the respective operators. While the Group uses its best estimates and judgement, actual results could differ from these estimates. Expected timing of expenditure can also change, for example in response to changes in laws and regulations or their interpretation, and/or due to changes in commodity prices. The payment dates are uncertain and depend on the production lives of the respective fields. Management does not expect any reasonable change in the expected timing of decommissioning to have a material effect on the decommissioning provisions, assuming cash flows remain unchanged. Decommissioning costs are expected to be incurred over the next 40 years. Whereas previously the Group used a uniform nominal discount rate over all future years, it has now revised its methodology to use a short-to-medium-term nominal discount rate and a long-term nominal discount rate. The Group uses a nominal discount rate of 4.38% for the first five years and 4.86% thereafter (31 December 2023: 4.60% for all years), based on the average risk-free rate over the second half of 2024, to discount the estimated costs. The inflation rate applied to estimated costs is 2.0% (2023: 2.0%). Given the long-term nature of the Group\u2019s decommissioning liabilities and the historic compounded inflation rates in the industry, management do not believe that the current short-term inflationary pressures will have a material impact on the decommissioning liabilities of the Group. A reduction or an increase in this discount rate of 1% would increase or reduce the decommissioning liabilities by approximately $288 million or $247 million, respectively (2023: $223 million or $188 million, respectively), and is not expected to have a material impact on the corresponding decommissioning reimbursement asset. For further details regarding the estimated value, inputs and assumptions refer to note 23. Given the large number of variables involved, management consider that it is not practical to provide sensitivities for the various other individual assumptions but the aggregated impact of related changes in the next 12 months could be material
Taxation estimates
The Group\u2019s operations are subject to a number of specific tax rules which apply to exploration, development and production companies such as the Energy Profits Levy at 35% to 31 October 2024 and 38% thereafter, ring-fenced
Corporation Tax at 30%, the Supplementary Charge of 10% and the application of investment allowances. In addition, the tax provision is prepared before the relevant companies have filed their tax returns with the relevant tax
authorities and, significantly, before these have been agreed. As a result of these factors, the tax provision process necessarily involves the use of a number of judgements and estimates, including those required in calculating the
effective tax rate. The Group recognises deferred tax assets on unused tax losses where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding
the likelihood of future taxable profits and the amount of deferred tax that can be recognised. Further details regarding the estimated value and related inputs are set out in note 28.
The Group\u2019s deferred tax assets are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised, including as a result of Group re-organisations and
asset transfers. In accordance with IAS 12 Income Taxes, the Group assesses the recoverability of its deferred tax assets at each period end. Consistent with the impairment sensitivity described above, as at 31 December 2024, a 20%
reduction in future revenues, with all other assumptions held constant, would eliminate current headroom and result in a deferred tax asset derecognition of $284 million (2023: $304 million). It should be noted that mitigating actions
are considered to be available to materially offset this impact. The $284 million (2023: $304 million) derecognition assumes that cash flows are equivalent to taxable profits and that any reorganisation required to utilise certain deferred
tax assets does not result in a displacement of other balances. As disclosed in note 28, there are unrecognised allowances of up to circa $150 million that have no expiry date and could be recognised in future periods if future revenue
from oil and gas activities increases and/or further actions are undertaken.
Other areas of estimation
The key assumptions concerning the future, and other sources of estimation uncertainty at the reporting period, that are not expected to cause a material adjustment to the carrying amounts of assets and liabilities within the next
financial year, are discussed below:
Business combinations
In 2024, the Group has made a material business combination \u2013 see note 17 for further details of the provisional purchase price allocation, including the assets and liabilities acquired and the goodwill arising on the transaction. This has
been accounted for as a business combination under IFRS 3. The assets and liabilities identified in the purchase price allocation include oil and gas assets, decommissioning liabilities, deferred tax assets and liabilities, and working capital.
The total consideration payable includes both the market value of new ordinary shares issued at the date of completion and a monetary settlement based on working capital movements, and certain other transactions such as dividend
payments, between the economic effective date of 1 July 2024 and date of completion. The amount payable under this monetary settlement is discussed further in note 17.
The calculation of the fair value of the oil and gas assets acquired requires the Group to estimate the future cash flows expected to arise from the assets of the acquired business using discounted cash flow models. Key assumptions
and estimates include: commodity prices, discount rates and oil and gas reserves estimates. See above estimates in the impairment of oil and gas assets and goodwill section and estimates in oil and gas reserves and contingent resources
section for further details regarding these assumptions. In addition, the Group has considered the value that a market participant would prescribe to prospective resources in determining the fair value of the oil and gas assets acquired.
In determining the value of the deferred tax asset recognised on the Business Combination, the Group has also made assumptions in respect of the amount of tax losses brought forward, which will be available to offset against future
taxable profits of the Group.
Critical accounting judgements
The following are the critical judgements, apart from those involving estimation (which are presented separately above), that the Directors have made in applying the Group\u2019s accounting policies and that have the most significant effect
on the amounts recognised in the financial statements.
Cambo and Rosebank carrying values
Management has reviewed the pre-tax carrying value of the Cambo field of $391 million or post tax $234 million (2023: pre-tax $391 million or post-tax $234 million) and has concluded that due to the licence extension to 31 March
2026 and the detailed plans in place for final investment decision (FID), there are currently no indicators of impairment. The Group is actively engaging with potential farm-in partners to secure an aligned joint venture partnership
that would help progress the project towards FID and assist in obtaining additional funding for the project. Management has submitted a request for a further 18 month extension of the licence to 30 September 2027 and to remove
a milestone commitment that would otherwise require a joint venture partner to be secured by 31 March 2025, with the latter no longer considered by management as a commercial pre-requisite for the project to proceed to
development following completion of the Eni UK Business Combination and the consequential increase in the scale and funding capability of the Group. A decision in respect of this request is expected by the North Sea Transition
Authority (NSTA) by the end of the second quarter of 2025. Details of contingent consideration in respect of Cambo are set out in note 26.
Similarly, management has reviewed the pre-tax carrying value of the Rosebank field of $617 million or post-tax $304 million (31 December 2023: pre-tax $413 million or post-tax $237 million). Although the first phase of the
Rosebank development had been sanctioned by the NSTA, it was subject to Judicial Review proceedings. On 30 January 2025, the Court of Session ruled that this consent had been unlawfully given in relation to the sanctioning of
the Rosebank field development and that a new consent application would be required, which included Scope 3 emissions. It did, however, permit the project to progress as planned whilst this new consent is sought from the Regulators
but that no oil could be extracted without this new consent. Whilst the outcome of the Judicial Review could be construed as an indicator of impairment, management has no reason to believe that this further consent will not be
forthcoming, and further management believe that the most likely outcome will be that the further consent will be granted and that the project will continue progressing as planned with first oil anticipated in 2026/27. As a result no
impairment charge is required.
", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-381": { "value": "Basis of measurement The consolidated financial statements have been prepared on a going concern basis using the historical cost convention, except for the revaluation of certain financial assets and financial liabilities, under International Financial Reporting Standards (IFRS), to fair value, including derivative instruments. Historical cost is generally based on the fair value consideration given in exchange for the assets and liabilities. ", "dimensions": { "concept": "ithacaenergyplc:DisclosureOfBasisOfMeasurement", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-383": { "value": "Going concern Management closely monitor the funding position of the Group, including monitoring compliance with covenants and available facilities to ensure sufficient headroom is maintained to fund operations. Management have considered a number of risks applicable to the Group that may have an impact on the Group\u2019s ability to continue as a going concern. Short-term and long-term cash forecasts are prepared on a weekly and quarterly basis respectively, along with any related sensitivity analysis. This allows proactive management of any business risk including, liquidity risk. The Directors consider the preparation of the financial statements on a going concern basis to be appropriate. This is due to the following key factors: \u2022 Continuing robust commodity price backdrop and a well-hedged portfolio over the next 12 months; \u2022 Reserves Based Lending (RBL) liquidity headroom of $850 million ($150 million drawn versus $1,000 million available), plus $383 million of cash as at 14 March 2025; and \u2022 Robust operational performance and a well-diversified portfolio.
Cash flow forecast \u2013 base case assumptions:
2025
H1 2026
Average oil price
$/bbl
71
68
Average gas price
p/th
107
96
Average hedged oil price (including floor price for zero cost collars)
$/bbl
75
70
Average hedged gas price (including floor price for zero cost collars)
p/th
91
89
The oil and gas price assumptions used in the going concern and viability assessments represent management's current best estimates at the date of approval of the Annual Report and Accounts, as supported by data from third-party analysis, of future commodity prices whereas the commodity prices used in impairment testing (see note 19) are based on market conditions at 31 December 2024. Owing to the ongoing fluctuations in commodity demand and price volatility, management prepared sensitivity analyses to the forecasts and applied a number of plausible downside scenarios, including decreases in production of 10%, reduced sales prices of 20% and increases in operating and capital expenditures of 10%. Management aggregated these scenarios to create a reasonable combined worst-case scenario. The sensitivity analysis showed that, without any consideration of the mitigation strategies within management\u2019s control, there was no reasonably possible scenario that would result in the business being unable to meet its liabilities as they fell due. In addition, reverse stress tests have been performed reflecting further reductions in commodity prices, prior to any mitigating actions, to determine at what levels prices would have to reach such that there is no liquidity headroom left. The stress tests demonstrated that the likelihood of the fall in prices required to cause a liquidity issue is considered sufficiently remote in the context of the mitigation strategies available to management. The mitigation strategies within the control of management include a reduction in uncommitted capital expenditure and variable opex savings in the low production scenario. The analysis demonstrated that the Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 June 2026 to continue trading. Based on their assessment of the Group\u2019s financial position in the period to 30 June 2026, the Directors believe that the Group will be able to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the financial statements. ", "dimensions": { "concept": "ifrs-full:DisclosureOfGoingConcernExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-384": { "value": "Basis of consolidation The consolidated financial statements of the Group includes the financial information of Ithaca Energy plc and all wholly-owned subsidiaries as listed per note 32. All intergroup transactions and balances have been eliminated on consolidation. Subsidiaries are all entities over which the Group has control. The plc controls an entity when the Group is exposed to or has rights to variable returns from its investments with the entity and has the ability to affect those returns through its power over the investee. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated on the date that control ceases.", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfConsolidationExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-439": { "value": "Subsidiaries are all entities over which the Group has control. The plc controls an entity when the Group is exposed to or has rights to variable returns from its investments with the entity and has the ability to affect those returns through its power over the investee. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated on the date that control ceases.", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSubsidiariesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-385": { "value": "Impact of climate change on the financial statements and related notes Judgements and estimates made in assessing the impact of climate change and the energy transition Climate change and the transition to a lower-carbon system were considered in preparing the consolidated financial statements. These may have the potential for significant impacts on the carrying values of the Group\u2019s assets and liabilities discussed below as well as on assets and liabilities that may be reflected in the future. There is also the potential for significant impact on future cash flows. There is generally a high level of uncertainty about the speed and magnitude of impacts of climate change which, together with limited historical data, provides significant challenges in the preparation of forecasts and financial plans with a wide range of potential future outcomes. The Group\u2019s ambition is to have one of the lowest carbon emission portfolios in the UK North Sea and to achieve Net Zero (whereby the amount of CO 2 added by the Group\u2019s activities is no greater than the amount taken away), on a net equity basis (by applying the Group\u2019s working interest in each respective asset to the total emissions of that asset), and in respect of Scope 1 and 2 emissions, by 2040, ten years ahead of the North Sea Transition Deal commitment. This will be achieved by optimising the Group\u2019s current portfolio in the short term and fundamentally transitioning the Group\u2019s portfolio over the medium to long term whilst maintaining forecast levels of production. Initiatives include, but are not limited to, operational improvements, offshore electrification, acquisition and investment into lower carbon intensity assets and the eventual cessation of production of mature fields which have higher carbon intensity. In addition, the Eni UK Business Combination has given the Group a portfolio with a relatively lower carbon footprint. Where the Group cannot reduce Scope 1 and Scope 2 emissions, Ithaca Energy will invest in carbon offsets to achieve the Group\u2019s goal of Net Zero. All new economic investment decisions include estimated costs of the energy transition based on existing technology and estimated costs of carbon and these opportunities are assessed on their climate impact potential and alignment with Ithaca Energy\u2019s Net Zero target, taking into account both greenhouse gas volumes and emissions intensity. Specific considerations of the potential impacts of climate change on significant judgements and estimates used in the consolidated financial statements are considered below. The items outlined below are likely to manifest themselves over a number of years and are, therefore, not generally considered to represent 'key sources of estimation uncertainty' as required by IAS 1 (being those which could have a material impact on the Group\u2019s results in the 12 months following the date of the consolidated statement of financial position) which are separately disclosed later in this note. Impairment of goodwill and property, plant and equipment The energy transition has the potential to significantly impact future commodity and carbon prices in that as the UK and global energy system decarbonises, reduced demand for oil and gas products in favour of low carbon alternatives could cause oil and gas prices to fall which would, in turn, affect the recoverable amount of goodwill and property, plant and equipment. In the current period management\u2019s estimate of the long-term commodity price assumptions are, in nominal terms from 2031, $83/bbl for Brent Crude and 87p/therm for UK NBP gas. Further details of climate change, including a sensitivity in this area are provided in note 19. Recoverable values used for impairment testing for all cash-generating units (CGUs) include the estimated cost of UK carbon emissions allowances in real terms for CO2 e of \u00a350/tonne, \u00a370/tonne and \u00a380/tonne for 2025,2026 and 2027 respectively. The recoverable value of CGU\u2019s may be impacted by future carbon pricing legislation changes, which could increase operating costs through higher emissions allowances or the introduction of other carbon pricing mechanisms. Electrification of offshore operations for specific assets is planned in line with the Group\u2019s 2040 Net Zero ambitions and where feasible based on existing technology, estimated electrification costs of a market participant are included within the assessment of the recoverable value of the relevant CGU. Property, plant and equipment \u2013 depreciation and useful economic lives The energy transition has the potential to reduce the expected useful economic lives of assets and hence accelerate depreciation charges. Although no changes have been identified or recognised to date, as noted in the Strategic Report on page 60, it is anticipated that certain higher emission-intensity assets such as FPF-1 and Alba will cease production in the medium term and will be replaced by new lower-emission intensity assets. Management does not currently expect the useful economic lives of the Group\u2019s reported property, plant and equipment to significantly change solely as a result of the energy transition. However, significant capital expenditure is still required for ongoing projects and therefore, the useful lives of future capital expenditure may be different. Intangible assets \u2013 exploration and evaluation assets The impacts of climate change and the energy transition may affect the viability of exploration prospects, for example due to the impact on future commodity and carbon prices (as explained above) or due to the increased risk of regulatory challenge as prospects progress through to development. The recoverability of the existing intangibles was considered during 2024, however, no significant write-offs were identified as a result of climate change considerations. Viability of these assets will continue to be assessed on a regular basis. Decommissioning provisions Most of the Group\u2019s existing decommissioning obligations are estimated to be completed over the course of the next 20 years. The impacts of climate change and the energy transition may bring forward the expected timing of decommissioning activity, increasing the present value of the associated decommissioning provisions. The potential impact of a reasonably possible acceleration of estimated decommissioning dates, which considers the potential impact of the energy transition, is considered to be two years. The impact of such an acceleration of cessation of production across the Group\u2019s entire producing portfolio would result in an increase in the decommissioning provision of approximately $93 million (2023: $69 million). The risk in this area may increase if key assets within the Group\u2019s existing exploration, appraisal and development portfolio proceed to the production stage, as this is likely to significantly extend the life of the Group\u2019s portfolio, in some cases to 2050 or beyond. While the pace of the transition to a lower-carbon economy is uncertain, oil and gas demand is expected to remain a key element of the energy mix for many years based on stated policies, commitments and announced pledges to reduce emissions. Therefore, given the estimated useful lives of the Group\u2019s oil and gas portfolio, a material adverse change is not anticipated to the carrying value of the Group\u2019s assets and liabilities in the short-term as a result of climate change and the transition to a lower-carbon economy. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEnvironmentRelatedExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-386": { "value": "Business combinations Business combinations are accounted for using the acquisition method. The cost of a business combination is measured as the fair value of the consideration given for the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of completion of the business combination. Transaction costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the date of the business combination. The excess of the cost of the business combination over the fair value of the Group\u2019s share of the identifiable net assets acquired is recorded as goodwill. If the cost of the business combination is less than the Group\u2019s share of the net assets acquired, the difference is recognised directly in the consolidated statement of profit or loss as a gain on bargain purchase.
Goodwill
Capitalisation
Goodwill is initially recognised and measured as set out above. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses.
Impairment
Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU or Group of
CGUs to which the goodwill relates. If the recoverable amount of a CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of goodwill allocated to the unit and then to the other assets of the
unit pro-rata based on the carrying amount of each asset in the unit. Any impairment loss is recognised in the consolidated statement of profit or loss. Impairment losses relating to goodwill cannot be reversed in future periods. The CGU for the
purposes of the goodwill test is the North Sea, i.e. the entire Group portfolio of oil and gas assets which is consistent with the operating segment view of the business.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsAndGoodwillExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-440": { "value": "Business combinations Business combinations are accounted for using the acquisition method. The cost of a business combination is measured as the fair value of the consideration given for the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of completion of the business combination. Transaction costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the date of the business combination. The excess of the cost of the business combination over the fair value of the Group\u2019s share of the identifiable net assets acquired is recorded as goodwill. If the cost of the business combination is less than the Group\u2019s share of the net assets acquired, the difference is recognised directly in the consolidated statement of profit or loss as a gain on bargain purchase. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-442": { "value": "Goodwill Capitalisation Goodwill is initially recognised and measured as set out above. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Impairment Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU or Group of CGUs to which the goodwill relates. If the recoverable amount of a CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of goodwill allocated to the unit and then to the other assets of the unit pro-rata based on the carrying amount of each asset in the unit. Any impairment loss is recognised in the consolidated statement of profit or loss. Impairment losses relating to goodwill cannot be reversed in future periods. The CGU for the purposes of the goodwill test is the North Sea, i.e. the entire Group portfolio of oil and gas assets which is consistent with the operating segment view of the business. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForGoodwillExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-474": { "value": "Impairment Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU or Group of CGUs to which the goodwill relates. If the recoverable amount of a CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of goodwill allocated to the unit and then to the other assets of the unit pro-rata based on the carrying amount of each asset in the unit. Any impairment loss is recognised in the consolidated statement of profit or loss. Impairment losses relating to goodwill cannot be reversed in future periods. The CGU for the purposes of the goodwill test is the North Sea, i.e. the entire Group portfolio of oil and gas assets which is consistent with the operating segment view of the business.
Impairment
For impairment review purposes the Group\u2019s oil and gas assets are aggregated into CGUs typically on a field-by-field basis for development and production assets in accordance with IAS 36, and on a North Sea segment basis for
exploration and evaluation assets in accordance with IFRS 6. A review is carried out at each reporting date for any indicators that the carrying value of the Group\u2019s assets may be impaired. Such reviews are carried out on a field-by-field
basis for both development and production assets and exploration and evaluation assets. For assets where there are such indicators, an impairment test is carried out on the CGU. The impairment test involves comparing the carrying
value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use. If the recoverable amount of an asset is estimated to be less than its carrying
amount, the carrying amount of the asset is reduced to the recoverable amount. The resulting impairment losses are written off to the consolidated statement of profit or loss. Previously impaired assets (excluding goodwill) are reviewed
for possible reversal of previous impairment at each reporting date. The maximum possible reversal is capped at the net book value
had the asset not been impaired in the past. Where an exploration and evaluation licence is relinquished, amounts capitalised in respect of the licence are written off to profit or loss in the period in which the licence is relinquished.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfNonfinancialAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-498": { "value": "Impairment Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU or Group of CGUs to which the goodwill relates. If the recoverable amount of a CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of goodwill allocated to the unit and then to the other assets of the unit pro-rata based on the carrying amount of each asset in the unit. Any impairment loss is recognised in the consolidated statement of profit or loss. Impairment losses relating to goodwill cannot be reversed in future periods. The CGU for the purposes of the goodwill test is the North Sea, i.e. the entire Group portfolio of oil and gas assets which is consistent with the operating segment view of the business. Impairment of financial assets For trade receivables and accrued income, the Group applies a simplified approach in calculating expected credit losses (ECLs). Therefore, the Group does not track changes in credit risk, but instead, recognises any material loss allowance based on lifetime ECLs at each reporting date. For all other financial assets, the Group measures the loss allowance using 12-month expected credit losses unless there was a significant increase in credit risk since initial recognition in which case the loss allowance is measured using lifetime expected credit losses. In making this assessment whether the credit risk increased significantly since initial recognition, the Group considers both quantitative and qualitative information that is reasonable and supportable, including historical experience and forward-looking information that is available without undue cost or effort. The Group considers that the credit risk increased significantly since initial recognition when the credit rating changes, the debtor has significant financial difficulty or if there was a breach of contract. For balances that are beyond 30 days overdue it is presumed to be an indicator of a significant increase in credit risk. The Group considers a financial asset in default when contractual payments are 90 days past due. However, in certain cases, the Group may also consider a financial asset to be in default when internal or external information indicates that the Group is unlikely to receive the outstanding contractual amounts in full before taking into account any credit enhancements held by the Group. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. Financial assets written off may still be subject to enforcement activities under the Group\u2019s recovery procedures, taking into account legal advice where appropriate. Any recoveries made are recognised in profit or loss. Impairment For impairment review purposes the Group\u2019s oil and gas assets are aggregated into CGUs typically on a field-by-field basis for development and production assets in accordance with IAS 36, and on a North Sea segment basis for exploration and evaluation assets in accordance with IFRS 6. A review is carried out at each reporting date for any indicators that the carrying value of the Group\u2019s assets may be impaired. Such reviews are carried out on a field-by-field basis for both development and production assets and exploration and evaluation assets. For assets where there are such indicators, an impairment test is carried out on the CGU. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to the recoverable amount. The resulting impairment losses are written off to the consolidated statement of profit or loss. Previously impaired assets (excluding goodwill) are reviewed for possible reversal of previous impairment at each reporting date. The maximum possible reversal is capped at the net book value had the asset not been impaired in the past. Where an exploration and evaluation licence is relinquished, amounts capitalised in respect of the licence are written off to profit or loss in the period in which the licence is relinquished. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-387": { "value": "
Interest in joint ventures
Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are
classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor.
The Group\u2019s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its proportionate share of assets held jointly), its liabilities (including its proportionate share
of liabilities incurred jointly), its revenue from the sale of its proportionate share of the output arising from the joint operation and its expenses (including its proportionate share of any expenses incurred jointly).
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-473": { "value": "Interest in joint ventures Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Group\u2019s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its proportionate share of assets held jointly), its liabilities (including its proportionate share of liabilities incurred jointly), its revenue from the sale of its proportionate share of the output arising from the joint operation and its expenses (including its proportionate share of any expenses incurred jointly). ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociates", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-441": { "value": "Interest in joint ventures Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Group\u2019s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its proportionate share of assets held jointly), its liabilities (including its proportionate share of liabilities incurred jointly), its revenue from the sale of its proportionate share of the output arising from the joint operation and its expenses (including its proportionate share of any expenses incurred jointly). ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-388": { "value": "
Revenue
The sale of crude oil, gas or condensate represents a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue is accordingly recognised
for this performance obligation when control over the corresponding commodity is transferred to the customer. Revenue is recognised at a point in time and is measured based on the consideration to which the Group expects to be
entitled in a contract with a customer and excludes amounts collected for third parties. Details of hedging gains and losses presented in revenue are discussed in the hedging accounting policy set out below.
Tariff income is recognised as the underlying commodity is shipped through the pipeline network based on established tariff rates.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRecognitionOfRevenue", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-389": { "value": "
Foreign currency translation
Items included in these consolidated financial statements are measured using the currency of the primary economic environment in which the Group and its subsidiaries operate (the functional currency). The consolidated financial
statements are presented in US Dollars, which is the Group\u2019s presentation currency as well as the functional currency of the Parent Company and each of its subsidiaries. In preparing the financial statements of the parent and its
subsidiaries, transactions in currencies other than the entity\u2019s functional currency (foreign currencies) are recognised at the rates of exchange prevailing on the dates of the transactions. At each reporting date, monetary assets and
liabilities that are denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the
date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated.
Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the
statement of profit or loss.
Exchange differences are recognised in profit or loss in the period in which they arise except for:
\u2022 Exchange differences on foreign currency borrowings relating to assets under construction for future productive use, which are included in the cost of those assets when they are regarded as an adjustment to interest costs on those
foreign currency borrowings;
\u2022 Exchange differences on transactions entered into to hedge certain foreign currency risks (see below under financial instruments/hedge accounting).
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-390": { "value": "Dividend distribution Dividend distribution to the Company\u2019s shareholders is recognised as a liability in the Company\u2019s financial statements in the period in which the dividends are approved by the Company\u2019s shareholders. Details of dividends paid and declared are set out in note 34 ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDividendsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-391": { "value": "Financial instruments All financial instruments are initially recognised at fair value on the statement of financial position. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. The difference between the carrying amount of the financial asset derecognised and the consideration received/receivable is recognised in profit or loss. The Group derecognises financial liabilities when, and only when, the Group\u2019s obligations are discharged, cancelled or have expired. The Group considers whether refinancing arrangements represent settlement of the existing debt and issuance of a new debt or an exchange or modification of the previous debt. In making this assessment, the Group considers, amongst other factors, pre-existing early redemption options in the original agreement, the group of lenders to which the new debt is offered and any preferential terms or rights given to the original lenders. Where the new debt is considered to represent an arms-length market offering, the issuance of the new debt is viewed as separate from the extinguishment of the old debt and is treated as the derecognition of the original liability and the recognition of a new liability. The difference between the carrying amount of the financial liability derecognised and the consideration paid/payable (excluding consideration payable for fees incurred on the new liability or accrued interest) is recognised in profit or loss. IFRS 9 classifications Cash and cash equivalents are classified at amortised cost which equates to its fair value. Accounts receivable and long-term receivables are classified and carried at amortised cost less expected credit losses. These items have a business model of held to collect and the terms of the financial instrument meet the classification of solely payments of interest on principle outstanding. Accounts payable, accrued liabilities, certain other long-term liabilities, and borrowings are classified as other financial liabilities and carried at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium. Contingent consideration is measured at fair value though profit or loss. Although the Group does not intend to trade its derivative financial instruments, they are required to be carried at fair value with the treatment of fair value movements explained further below. Transaction costs, presentation and cash flows Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability (excluding the costs directly attributable to the new loan commitment facilities) have been included in the carrying value of the related financial asset or liability and are amortised to consolidated net earnings over the life of the financial instrument using the effective interest method. Directly attributable fees paid on the establishment of new loan commitment facilities are capitalised to the extent that it is probable that some or all of the facility will be drawn down. These costs are recognised on a systematic basis over the period the Group is able to draw down. Fees that are calculated based on the usage of the facility (including letter of credit fees) are expensed as incurred. Borrowings are presented as non-current when they are not due to be settled within twelve months after the reporting period or where the Group has the right at the end of the reporting period to defer settlement for at least twelve months after the reporting period. Cash flows relating to refinancing are presented in the Statement of Cash Flows on a net basis where that reflects the actual cash flows received by the Group. The refinancing proceeds in the Statement of Cash Flows are stated after deduction of fees which were deducted from the amount paid to the Group. Other fees paid on refinancing are presented as a separate line item within financing activities or within Interest and charges paid in the Statement of Cash Flows. Impairment of financial assets For trade receivables and accrued income, the Group applies a simplified approach in calculating expected credit losses (ECLs). Therefore, the Group does not track changes in credit risk, but instead, recognises any material loss allowance based on lifetime ECLs at each reporting date. For all other financial assets, the Group measures the loss allowance using 12-month expected credit losses unless there was a significant increase in credit risk since initial recognition in which case the loss allowance is measured using lifetime expected credit losses. In making this assessment whether the credit risk increased significantly since initial recognition, the Group considers both quantitative and qualitative information that is reasonable and supportable, including historical experience and forward-looking information that is available without undue cost or effort. The Group considers that the credit risk increased significantly since initial recognition when the credit rating changes, the debtor has significant financial difficulty or if there was a breach of contract. For balances that are beyond 30 days overdue it is presumed to be an indicator of a significant increase in credit risk. The Group considers a financial asset in default when contractual payments are 90 days past due. However, in certain cases, the Group may also consider a financial asset to be in default when internal or external information indicates that the Group is unlikely to receive the outstanding contractual amounts in full before taking into account any credit enhancements held by the Group. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. Financial assets written off may still be subject to enforcement activities under the Group\u2019s recovery procedures, taking into account legal advice where appropriate. Any recoveries made are recognised in profit or loss. Derivative financial instruments The Group enters into a variety of derivative financial instruments to manage its exposure to commodity risks, interest rate and foreign exchange rate risks. These instruments include: commodity swaps, collars and options; foreign exchange forward contracts and collars; and interest rate swaps. Further details of derivative financial instruments are disclosed in notes 30 and 31. 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 on remeasurement of derivatives is recognised in profit or loss immediately unless the derivative is designated in a hedge relationship 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. A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a financial liability. Derivatives are not offset in the financial statements unless the Group has both a legally enforceable right and intention to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than 12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected to be realised or settled in less than 12 months are presented as current assets or current liabilities. Hedge accounting The Group designates certain derivatives as hedging instruments in respect of commodity risks in cash flow hedges. At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is highly effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk. 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 hedging instrument, 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 cost of hedging 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 cost of hedging reserve is reclassified to profit or loss on a rational basis \u2013 the Group applies straight-line amortisation. Those reclassified amounts are recognised in profit or loss in the same line as the hedged item. If the Group expects that some or all of the loss accumulated in the cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss. The effective portion of changes in the fair value of derivatives and other qualifying hedging instruments that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated under the heading of cash flow hedge reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss, and is included in the 'other gains and losses' line item. 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 revenue line as the recognised hedged item. However, when the hedged forecast transaction results in the recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognised in other comprehensive income and accumulated in equity are removed from equity and included in the initial measurement of the cost of the non-financial asset or non-financial liability. This transfer does not affect other comprehensive income. Furthermore, if the Group expects that some or all of the loss accumulated in the cash flow hedge reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss. The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in the cash flow hedge reserve is reclassified immediately to profit or loss. If a hedge of a transaction-related item is discontinued part way through the life of the hedge (e.g. due to early termination of the swap, hedging resets), but the hedged item is still expected to occur, the amounts deferred in equity would remain in equity until the earlier of: (i) the hedged transaction occurring; or (ii) expectation that the amount deferred in equity will not be recovered in the future periods. Note 30 and note 31 set out details of the fair values of the derivative instruments used for hedging purposes, and movements in the cash flow hedge reserve and cost of hedging reserve in equity are detailed in note 30.
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 borrowing costs are expensed as incurred. Borrowing costs directly attributable to E&E assets are not capitalised and are expensed directly to
profit or loss when incurred.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-475": { "value": "All financial instruments are initially recognised at fair value on the statement of financial position. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. The difference between the carrying amount of the financial asset derecognised and the consideration received/receivable is recognised in profit or loss. The Group derecognises financial liabilities when, and only when, the Group\u2019s obligations are discharged, cancelled or have expired. The Group considers whether refinancing arrangements represent settlement of the existing debt and issuance of a new debt or an exchange or modification of the previous debt. In making this assessment, the Group considers, amongst other factors, pre-existing early redemption options in the original agreement, the group of lenders to which the new debt is offered and any preferential terms or rights given to the original lenders. Where the new debt is considered to represent an arms-length market offering, the issuance of the new debt is viewed as separate from the extinguishment of the old debt and is treated as the derecognition of the original liability and the recognition of a new liability. The difference between the carrying amount of the financial liability derecognised and the consideration paid/payable (excluding consideration payable for fees incurred on the new liability or accrued interest) is recognised in profit or loss. IFRS 9 classifications Cash and cash equivalents are classified at amortised cost which equates to its fair value. Accounts receivable and long-term receivables are classified and carried at amortised cost less expected credit losses. These items have a business model of held to collect and the terms of the financial instrument meet the classification of solely payments of interest on principle outstanding. Accounts payable, accrued liabilities, certain other long-term liabilities, and borrowings are classified as other financial liabilities and carried at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium. Contingent consideration is measured at fair value though profit or loss. Although the Group does not intend to trade its derivative financial instruments, they are required to be carried at fair value with the treatment of fair value movements explained further below. Transaction costs, presentation and cash flows Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability (excluding the costs directly attributable to the new loan commitment facilities) have been included in the carrying value of the related financial asset or liability and are amortised to consolidated net earnings over the life of the financial instrument using the effective interest method. Directly attributable fees paid on the establishment of new loan commitment facilities are capitalised to the extent that it is probable that some or all of the facility will be drawn down. These costs are recognised on a systematic basis over the period the Group is able to draw down. Fees that are calculated based on the usage of the facility (including letter of credit fees) are expensed as incurred. Borrowings are presented as non-current when they are not due to be settled within twelve months after the reporting period or where the Group has the right at the end of the reporting period to defer settlement for at least twelve months after the reporting period. Cash flows relating to refinancing are presented in the Statement of Cash Flows on a net basis where that reflects the actual cash flows received by the Group. The refinancing proceeds in the Statement of Cash Flows are stated after deduction of fees which were deducted from the amount paid to the Group. Other fees paid on refinancing are presented as a separate line item within financing activities or within Interest and charges paid in the Statement of Cash Flows. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-443": { "value": "The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. The difference between the carrying amount of the financial asset derecognised and the consideration received/receivable is recognised in profit or loss. The Group derecognises financial liabilities when, and only when, the Group\u2019s obligations are discharged, cancelled or have expired. The Group considers whether refinancing arrangements represent settlement of the existing debt and issuance of a new debt or an exchange or modification of the previous debt. In making this assessment, the Group considers, amongst other factors, pre-existing early redemption options in the original agreement, the group of lenders to which the new debt is offered and any preferential terms or rights given to the original lenders. Where the new debt is considered to represent an arms-length market offering, the issuance of the new debt is viewed as separate from the extinguishment of the old debt and is treated as the derecognition of the original liability and the recognition of a new liability. The difference between the carrying amount of the financial liability derecognised and the consideration paid/payable (excluding consideration payable for fees incurred on the new liability or accrued interest) is recognised in profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerecognitionOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-444": { "value": "Impairment of financial assets For trade receivables and accrued income, the Group applies a simplified approach in calculating expected credit losses (ECLs). Therefore, the Group does not track changes in credit risk, but instead, recognises any material loss allowance based on lifetime ECLs at each reporting date. For all other financial assets, the Group measures the loss allowance using 12-month expected credit losses unless there was a significant increase in credit risk since initial recognition in which case the loss allowance is measured using lifetime expected credit losses. In making this assessment whether the credit risk increased significantly since initial recognition, the Group considers both quantitative and qualitative information that is reasonable and supportable, including historical experience and forward-looking information that is available without undue cost or effort. The Group considers that the credit risk increased significantly since initial recognition when the credit rating changes, the debtor has significant financial difficulty or if there was a breach of contract. For balances that are beyond 30 days overdue it is presumed to be an indicator of a significant increase in credit risk. The Group considers a financial asset in default when contractual payments are 90 days past due. However, in certain cases, the Group may also consider a financial asset to be in default when internal or external information indicates that the Group is unlikely to receive the outstanding contractual amounts in full before taking into account any credit enhancements held by the Group. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. Financial assets written off may still be subject to enforcement activities under the Group\u2019s recovery procedures, taking into account legal advice where appropriate. Any recoveries made are recognised in profit or loss. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfFinancialAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-492": { "value": "Derivative financial instruments The Group enters into a variety of derivative financial instruments to manage its exposure to commodity risks, interest rate and foreign exchange rate risks. These instruments include: commodity swaps, collars and options; foreign exchange forward contracts and collars; and interest rate swaps. Further details of derivative financial instruments are disclosed in notes 30 and 31. 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 on remeasurement of derivatives is recognised in profit or loss immediately unless the derivative is designated in a hedge relationship 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. A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a financial liability. Derivatives are not offset in the financial statements unless the Group has both a legally enforceable right and intention to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than 12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected to be realised or settled in less than 12 months are presented as current assets or current liabilities. Hedge accounting The Group designates certain derivatives as hedging instruments in respect of commodity risks in cash flow hedges. At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is highly effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk. 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 hedging instrument, 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 cost of hedging 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 cost of hedging reserve is reclassified to profit or loss on a rational basis \u2013 the Group applies straight-line amortisation. Those reclassified amounts are recognised in profit or loss in the same line as the hedged item. If the Group expects that some or all of the loss accumulated in the cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss. The effective portion of changes in the fair value of derivatives and other qualifying hedging instruments that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated under the heading of cash flow hedge reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss, and is included in the 'other gains and losses' line item. 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 revenue line as the recognised hedged item. However, when the hedged forecast transaction results in the recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognised in other comprehensive income and accumulated in equity are removed from equity and included in the initial measurement of the cost of the non-financial asset or non-financial liability. This transfer does not affect other comprehensive income. Furthermore, if the Group expects that some or all of the loss accumulated in the cash flow hedge reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss. The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in the cash flow hedge reserve is reclassified immediately to profit or loss. If a hedge of a transaction-related item is discontinued part way through the life of the hedge (e.g. due to early termination of the swap, hedging resets), but the hedged item is still expected to occur, the amounts deferred in equity would remain in equity until the earlier of: (i) the hedged transaction occurring; or (ii) expectation that the amount deferred in equity will not be recovered in the future periods. Note 30 and note 31 set out details of the fair values of the derivative instruments used for hedging purposes, and movements in the cash flow hedge reserve and cost of hedging reserve in equity are detailed in note 30. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-445": { "value": "Derivative financial instruments The Group enters into a variety of derivative financial instruments to manage its exposure to commodity risks, interest rate and foreign exchange rate risks. These instruments include: commodity swaps, collars and options; foreign exchange forward contracts and collars; and interest rate swaps. Further details of derivative financial instruments are disclosed in notes 30 and 31. 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 on remeasurement of derivatives is recognised in profit or loss immediately unless the derivative is designated in a hedge relationship 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. A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a financial liability. Derivatives are not offset in the financial statements unless the Group has both a legally enforceable right and intention to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than 12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected to be realised or settled in less than 12 months are presented as current assets or current liabilities. Hedge accounting The Group designates certain derivatives as hedging instruments in respect of commodity risks in cash flow hedges. At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is highly effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk. 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 hedging instrument, 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 cost of hedging 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 cost of hedging reserve is reclassified to profit or loss on a rational basis \u2013 the Group applies straight-line amortisation. Those reclassified amounts are recognised in profit or loss in the same line as the hedged item. If the Group expects that some or all of the loss accumulated in the cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss. The effective portion of changes in the fair value of derivatives and other qualifying hedging instruments that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated under the heading of cash flow hedge reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss, and is included in the 'other gains and losses' line item. 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 revenue line as the recognised hedged item. However, when the hedged forecast transaction results in the recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognised in other comprehensive income and accumulated in equity are removed from equity and included in the initial measurement of the cost of the non-financial asset or non-financial liability. This transfer does not affect other comprehensive income. Furthermore, if the Group expects that some or all of the loss accumulated in the cash flow hedge reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss. The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in the cash flow hedge reserve is reclassified immediately to profit or loss. If a hedge of a transaction-related item is discontinued part way through the life of the hedge (e.g. due to early termination of the swap, hedging resets), but the hedged item is still expected to occur, the amounts deferred in equity would remain in equity until the earlier of: (i) the hedged transaction occurring; or (ii) expectation that the amount deferred in equity will not be recovered in the future periods. Note 30 and note 31 set out details of the fair values of the derivative instruments used for hedging purposes, and movements in the cash flow hedge reserve and cost of hedging reserve in equity are detailed in note 30. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-476": { "value": "Hedge accounting The Group designates certain derivatives as hedging instruments in respect of commodity risks in cash flow hedges. At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is highly effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk. 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 hedging instrument, 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 cost of hedging 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 cost of hedging reserve is reclassified to profit or loss on a rational basis \u2013 the Group applies straight-line amortisation. Those reclassified amounts are recognised in profit or loss in the same line as the hedged item. If the Group expects that some or all of the loss accumulated in the cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss. The effective portion of changes in the fair value of derivatives and other qualifying hedging instruments that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated under the heading of cash flow hedge reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss, and is included in the 'other gains and losses' line item. 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 revenue line as the recognised hedged item. However, when the hedged forecast transaction results in the recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognised in other comprehensive income and accumulated in equity are removed from equity and included in the initial measurement of the cost of the non-financial asset or non-financial liability. This transfer does not affect other comprehensive income. Furthermore, if the Group expects that some or all of the loss accumulated in the cash flow hedge reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss. The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in the cash flow hedge reserve is reclassified immediately to profit or loss. If a hedge of a transaction-related item is discontinued part way through the life of the hedge (e.g. due to early termination of the swap, hedging resets), but the hedged item is still expected to occur, the amounts deferred in equity would remain in equity until the earlier of: (i) the hedged transaction occurring; or (ii) expectation that the amount deferred in equity will not be recovered in the future periods. Note 30 and note 31 set out details of the fair values of the derivative instruments used for hedging purposes, and movements in the cash flow hedge reserve and cost of hedging reserve in equity are detailed in note 30. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-395": { "value": "
Contingent and deferred consideration
Contingent consideration in relation to a business combination or asset acquisition is accounted for as a financial liability and measured at fair value at the date of acquisition with any subsequent remeasurements recognised in profit
or loss in accordance with IFRS 9. These fair values are generally based on risk-adjusted future cash flows discounted using appropriate discount rates. Changes in fair value of the contingent consideration that qualify as measurement
period adjustments are adjusted retrospectively, with corresponding adjustments against goodwill. Measurement period adjustments are adjustments that arise from additional information obtained during the 'measurement period'
(which cannot exceed one year from the date of the business combination) about facts and circumstances that existed at the date of the business combination.
The subsequent accounting for changes in the fair value of the contingent consideration that do not qualify as measurement period adjustments depends on how the contingent consideration is classified. Contingent consideration that
is classified as equity is not remeasured at subsequent reporting dates and its subsequent settlement is accounted for within equity. Other contingent consideration is remeasured to fair value at subsequent reporting dates with changes
in fair value recognised in profit or loss.
Deferred consideration is measured at amortised cost because the amount payable in the future is fixed.
Settlement of contingent consideration is recorded as investing outflows in the cash flow statement to the extent that cumulative amounts paid do not exceed the amount recognised at the date of acquisition, with any excess recorded
as an operating cash outflow. Settlement of deferred consideration is recorded as either an investing or financing outflow in the cash flow statement, depending on the substance of the arrangement at inception. Key considerations
in forming this judgement will include the extent of inferred financing costs included in the overall consideration arrangements at acquisition, the period of time over which the payments are made, the rationale for agreeing to defer
elements of the consideration and the general level of funding resources available to the Group at the time of acquisition.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-392": { "value": "
Cash and cash equivalents
For the purpose of the statement of cash flows, cash and cash equivalents include investments with an original maturity of three months or less. In the statement of financial position, cash and bank balances comprise cash (i.e. cash on
hand and demand deposits) and cash equivalents. Cash equivalents are short-term (generally with original maturity of three months or less), highly-liquid investments that are readily convertible to a known amount of cash and which
are subject to an insignificant risk of changes in value. Cash equivalents are held for the purpose of meeting short-term cash commitments rather than for investment or other purposes.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyToDetermineComponentsOfCashAndCashEquivalents", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-393": { "value": "
Inventories \u2013 hydrocarbon and materials
Inventories of materials are stated at the lower of cost and net realisable value. Cost comprises direct materials and, where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their
present location and condition. Cost is determined on the first-in, first-out method. Current hydrocarbon inventories are stated at net realisable value, which is based on estimated selling price less any further costs expected to be
incurred to completion and disposal/sale. Non-current oil and gas inventories are stated at historic cost. Provision is made for obsolete, slow-moving and defective items where appropriate.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForMeasuringInventories", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-396": { "value": "
Lifting or offtake arrangements
Lifting or offtake arrangements for oil and gas produced in certain of the Group\u2019s oil and gas properties 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 volume sold is an \u2018underlift\u2019 included within inventories, or an \u2018overlift\u2019 included within trade and other payables in the statement of financial position. Both are stated at
net realisable value using an observable year-end oil or gas market price. Movements during an accounting period are adjusted through cost of sales in the consolidated statement of profit or loss.
", "dimensions": { "concept": "ithacaenergyplc:DescriptionOfAccountingPolicyForLiftingOrOfftakeArrangements", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-394": { "value": "
Exploration and evaluation assets
Oil and gas expenditure \u2013 exploration and evaluation (E&E) assets
Geological and geophysical costs and costs incurred pre-licence are expensed as incurred. Costs directly associated with an exploration well are initially capitalised as an intangible asset until the drilling of the well is complete and the
results have been evaluated. These costs include employee remuneration, materials and fuel used, freight costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration
well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will
not occur, that is, the efforts are not successful, then the costs are expensed.
Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where
hydrocarbons were not found, are initially capitalised as an intangible asset. Upon external approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is first assessed for impairment
and, if required, an impairment loss is recognised. The remaining balance is then transferred to development and production (D&P) assets. If development is not approved and no further activity is expected to occur, then the costs
are expensed.
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the
geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required before production could begin
and where the economic viability of that major capital expenditure depends on the successful completion of further exploitation or appraisal work in the area remain capitalised on the balance sheet as long as such work is under way or
firmly planned.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForExplorationAndEvaluationExpenditures", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-397": { "value": "
Property, plant and equipment
Oil and gas expenditure \u2013 D&P assets
Capitalisation
Costs of bringing a field into production, including the cost of facilities, wells and subsea equipment, direct costs including staff costs together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P
asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form
a single D&P asset.
Depreciation
All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset generally
on a field-by-field basis. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed
to consider if their useful lives differ from the expected life of the D&P asset.
Non-oil and natural gas operations
Non-oil and gas assets are initially recorded at cost and depreciated over their estimated useful lives on a straight-line basis as follows:
Buildings 10 years
Computer and office equipment 3 years
Furniture and fittings 5 years
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-446": { "value": "Oil and gas expenditure \u2013 D&P assets Capitalisation Costs of bringing a field into production, including the cost of facilities, wells and subsea equipment, direct costs including staff costs together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset. Depreciation All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset generally on a field-by-field basis. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset. Non-oil and natural gas operations Non-oil and gas assets are initially recorded at cost and depreciated over their estimated useful lives on a straight-line basis as follows: Buildings 10 years Computer and office equipment 3 years Furniture and fittings 5 years ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-477": { "value": "Depreciation All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset generally on a field-by-field basis. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDepreciationExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-493": { "value": "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 borrowing costs are expensed as incurred. Borrowing costs directly attributable to E&E assets are not capitalised and are expensed directly to profit or loss when incurred. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialLiabilitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-447": { "value": "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 borrowing costs are expensed as incurred. Borrowing costs directly attributable to E&E assets are not capitalised and are expensed directly to profit or loss when incurred. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingCostsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-400": { "value": "
Decommissioning liabilities
The Group records the present value of legal obligations associated with the retirement of long-term tangible assets, such as producing well sites and processing plants, in the period in which they are incurred with a corresponding
increase in the carrying amount of the related long-term asset. Liabilities for decommissioning are recognised when the Group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and
restore the site on which it is located, and when a reliable estimate can be made. Where the obligation exists for a new facility or well, such as oil and gas production or transportation facilities, the obligation generally arises when the
asset is installed or the ground/environment is disturbed at the field location. In subsequent periods, the asset is adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The amount recognised
is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. Changes in decommissioning cost estimates for assets that have either been fully written off or have ceased
production are expensed as impairment charges in the period the change occurs. The carrying amounts of the associated decommissioning assets are depleted using the unit of production method in accordance with the depreciation
policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred. The unwinding of discount in the net present value of the total expected cost is treated as an interest
expense. Changes in the estimates are reflected prospectively over the remaining life of the field.
Where some or all of the expenditure required to settle a provision is expected to be reimbursed by another party, a reimbursement asset is recognised when, and only when, it is virtually certain that reimbursement will be received if the
entity settles the obligation. The amount recognised for the reimbursement may not exceed the amount of the provision.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDecommissioningRestorationAndRehabilitationProvisionsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-398": { "value": "
Taxation
Current tax
Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively
enacted by the reporting date. Taxable profit differs from net profit, as reported in the consolidated statement of profit or loss, because it excludes items of income or expense that are taxable or deductible in other accounting periods
and it further excludes items of income or expenses that are never taxable or deductible.
Deferred tax
Deferred tax is recognised using the liability method, providing for temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax is measured at the tax
rates that are expected to be applied to the temporary differences when they are forecast to reverse, based on the laws that have been enacted or substantively enacted at each balance sheet date. Details of changes in EPL and other
tax matters are set out in note 28. Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill and deferred tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction
other than business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred tax assets are recognised only to the extent that it is probable that future taxable profits will be available
against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each balance sheet date and all available evidence is considered in evaluating the recoverability of these deferred tax
assets. Deferred tax assets and liabilities are offset where there is a legally enforceable right to offset current tax assets and liabilities relating to taxes levied by the same taxation authority on either the same taxable entity or different
taxable entities where there is an intention to settle the balances on a net basis.
Deferred Petroleum Revenue Tax (PRT) assets are recognised where PRT relief on future decommissioning costs is probable.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForIncomeTaxExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-448": { "value": "Deferred tax Deferred tax is recognised using the liability method, providing for temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax is measured at the tax rates that are expected to be applied to the temporary differences when they are forecast to reverse, based on the laws that have been enacted or substantively enacted at each balance sheet date. Details of changes in EPL and other tax matters are set out in note 28. Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill and deferred tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred tax assets are recognised only to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each balance sheet date and all available evidence is considered in evaluating the recoverability of these deferred tax assets. Deferred tax assets and liabilities are offset where there is a legally enforceable right to offset current tax assets and liabilities relating to taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis. Deferred Petroleum Revenue Tax (PRT) assets are recognised where PRT relief on future decommissioning costs is probable. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDeferredIncomeTaxExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-399": { "value": "
Leases
The Group assesses at contract inception all arrangements to determine whether it is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for
consideration. The Group is not a lessor in any transactions, it is only a lessee. The Group recognises a right-of-use asset and a corresponding lease liability with respect to all lease arrangements in which it is the lessee. The Group
has elected to apply Paragraph 6 of IFRS 16 to short-term leases (defined as leases with a lease term of 12 months or less) and leases of low-value assets (such as tablets and personal computers, small items of office furniture and
telephones). Lease payments associated with these leases are expensed over the relevant lease term.
Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities
recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The right-of-use asset is depreciated over the useful life of the asset.
The Group\u2019s right-of-use assets are included in property, plant and equipment (note 15).
At the commencement date of the lease, the Group recognises lease liabilities measured at the present value of lease payments to be made over the lease term. In calculating the present value of lease payments, the Group uses its
incremental borrowing rate at the lease commencement date because the interest rate implicit in the lease is generally not readily determinable. After the commencement date, the amount of lease liabilities is increased to reflect the
accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments (e.g. changes to future
payments resulting from a change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the underlying asset.
The Group has elected to apply the practical expedient under IFRS 16.15 to account for lease and associated non-lease components as a single lease component on a class-of-asset basis.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-401": { "value": "
Maintenance expenditure
Expenditure on major maintenance refits or repairs is capitalised where it enhances the life or performance of an asset above its originally assessed standard of performance, replaces an asset or part of an asset which was separately
depreciated and which is then written off, or restores the economic benefits of an asset which has been fully depreciated. All other maintenance expenditure is charged to the statement of profit or loss as incurred.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForRepairsAndMaintenanceExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-402": { "value": "
Share-based payments
The Group issues equity-settled share-based payments to certain employees. Equity-settled share-based payments are measured at fair value at the date of grant. The fair value is expensed over the vesting term either on a straight-line
basis or as specified in the vesting terms, based on the Group\u2019s estimate of shares that will eventually vest and is adjusted for the effects of non-market-based vesting conditions.
Fair value is measured by using a Black-Scholes or other appropriate valuation model. The expected life used in the model is adjusted based on management\u2019s best estimate for the effects of non-transferability, exercise restrictions and
behavioural considerations.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForSharebasedPaymentTransactionsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-403": { "value": "
Retirement benefit costs
The Group operates a defined contribution pension scheme and payments into this plan are charged as an expense as they fall due. There is no further obligation to pay contributions into the plan once the contributions specified in the
plan rules have been paid.
Short-term employee benefits
A charge or liability is recognised for benefits accruing to employees in respect of salaries, bonuses, annual leave and sick leave in the period the related service is rendered at the undiscounted amount of the benefits expected to be paid
for that service. Charges or liabilities recognised in respect of short-term employee benefits are measured at the undiscounted amount of the benefits expected to be paid in exchange for the related service.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-404": { "value": "
Non-GAAP measures
In measuring the Group\u2019s adjusted operating performance, additional financial measures derived from the reported results have been used by management in order to eliminate factors which distort year-on-year comparisons.
The Group\u2019s adjusted performance is used to explain year-on-year changes when the effect of certain items is significant, including impairment charges or reversals, business combination costs, one-off finance charges related
to refinancing, the tax effect of these items where applicable and non-cash deferred tax charges on the increase in rate of EPL.
Adjusted EBITDAX, adjusted net income, adjusted EPS, unit operating expenditure, leverage ratio, adjusted net debt and certain other reported metrics are non-GAAP measures that are not specifically defined under IFRS or other
generally accepted accounting principles. Further details are set out on pages 249 to 252.
", "dimensions": { "concept": "ithacaenergyplc:DescriptionOfAccountingPolicyForNonGAAPMeasures", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-405": { "value": "
Changes in accounting pronouncements
The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2023 to 31 December 2024. There was no material impact from these or from any of
the amendments to existing standards and interpretations which were effective from 1 January 2024. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.
New and revised IFRS Standards in issue but not yet effective As at 31 December 2024 , the Group had not applied the following new Standards or revisions to existing IFRS Standards, that have been issued but are not yet effective. IFRS S1 General requirements for disclosure of sustainability related financial information IFRS S2 Climate related disclosures Amendments to SASB standards Amendments to the SASB standards to enhance their international applicability Amendments to IAS 21 Lack of exchangeability Amendments to IFRS 9 and IFRS 7 Amendments to the classification and measurement of financial instruments Amendments to IFRS 9 and IFRS 7 Contracts referencing nature-dependent electricity Annual improvements to IFRS Annual improvements to IFRS Accounting Standards \u2013 volume 11 IFRS 18 Presentation and disclosures in financial statements IFRS 19 Subsidiaries without public accountability: disclosures With the exception of IFRS S1, IFRS S2 and IFRS 18, the Group does not expect that the adoption of the new Standards or amendments to existing Standards, listed above, will have a material impact on the consolidated financial statements of the Group in future periods. The Group is currently assessing the impact of the sustainability and climate Standards which will apply from 1 January 2026 and the Group is also considering the impact of the adoption of IFRS 18 which will apply from 1 January 2027 onwards. ", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-449": { "value": "Changes in accounting pronouncements The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2023 to 31 December 2024. There was no material impact from these or from any of the amendments to existing standards and interpretations which were effective from 1 January 2024. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective. ", "dimensions": { "concept": "ifrs-full:DescriptionOfInitialApplicationOfStandardsOrInterpretations", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-450": { "value": "New and revised IFRS Standards in issue but not yet effective As at 31 December 2024 , the Group had not applied the following new Standards or revisions to existing IFRS Standards, that have been issued but are not yet effective. IFRS S1 General requirements for disclosure of sustainability related financial information IFRS S2 Climate related disclosures Amendments to SASB standards Amendments to the SASB standards to enhance their international applicability Amendments to IAS 21 Lack of exchangeability Amendments to IFRS 9 and IFRS 7 Amendments to the classification and measurement of financial instruments Amendments to IFRS 9 and IFRS 7 Contracts referencing nature-dependent electricity Annual improvements to IFRS Annual improvements to IFRS Accounting Standards \u2013 volume 11 IFRS 18 Presentation and disclosures in financial statements IFRS 19 Subsidiaries without public accountability: disclosures With the exception of IFRS S1, IFRS S2 and IFRS 18, the Group does not expect that the adoption of the new Standards or amendments to existing Standards, listed above, will have a material impact on the consolidated financial statements of the Group in future periods. The Group is currently assessing the impact of the sustainability and climate Standards which will apply from 1 January 2026 and the Group is also considering the impact of the adoption of IFRS 18 which will apply from 1 January 2027 onwards. ", "dimensions": { "concept": "ifrs-full:DescriptionOfExpectedImpactOfInitialApplicationOfNewStandardsOrInterpretations", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-406": { "value": "Critical judgements and key sources of estimation uncertainties Key sources of estimation uncertainty The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below. Estimates in oil and gas reserves and contingent resources The Group\u2019s estimates of oil and gas reserves and contingent resources, and the associated production forecasts, are used in the impairment testing of property plant and equipment and goodwill, in the measurement of depletion and decommissioning provisions, the measurement of certain elements of contingent consideration, the going concern assessment, the viability assessment and in the determination of whether deferred tax assets are recoverable. The business of the Group is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner. Estimates of oil and gas reserves and contingent resources require significant judgement. Factors such as the availability of geological and engineering data, reservoir performance data, drilling of new wells and estimates of future oil and gas prices all impact on the determination of the Group\u2019s estimates of its oil and gas reserves, which could result in different future production profiles affecting prospectively the discounted cash flows used in impairment testing. The Group\u2019s estimates of reserves and resource volumes used for accounting purposes are built up from historically-matched models for operated assets and principally from operators\u2019 estimates for non-operated assets. A review process is undertaken to compare the results of the Group\u2019s internal estimates to those of an independent consultant to understand any differences in underlying assumptions to ensure there are no significant unreconciled differences between the estimates. For the purposes of depletion and decommissioning estimates, the Group uses proved and probable reserves; and for the purposes of the impairment tests performed and deferred tax asset recoverability, the Group considers the same proved and probable reserves as well as risked resource volumes. These risking adjustments are reflective of management\u2019s assessment of technical and commercial factors that reflect the value considerations of a market participant. Changes in estimates of oil and gas reserves and resources resulting in different future production profiles will affect the discounted cash flows used in impairment testing, the anticipated date of decommissioning, the depletion charges in accordance with the unit of production method and the recoverability of deferred tax assets. The sensitivity of the Group\u2019s impairment tests and deferred tax recoverability assessments to key sources of estimation uncertainty, including reserves and resources, is discussed below.
Estimates in impairment of oil and gas assets and goodwill
Determination of whether the Group\u2019s oil and gas assets (note 15) or goodwill (note 18) have suffered any impairment requires an estimation of the recoverable amount of the CGU to which oil and gas assets and goodwill have been
allocated. Projected future cash flows are used to determine a fair value less cost to sell to establish the recoverable amount. Key assumptions and estimates in the impairment models relate to: commodity prices that are based on an
external view of forward curve prices that are considered to be a best estimate of what a market participant would use; discount rates which reflect management\u2019s estimate of a market participant post-tax weighted average cost of
capital; and oil and gas reserves and resources on a risked basis as described above. Management\u2019s estimates of a market participant\u2019s view of pricing and discount rates are supplied by an independent consultant.
The sensitivity of the Group\u2019s carrying amounts to these assumptions is illustrated by the impairments and reversals disclosed in note 19, and by the sensitivity disclosures in note 19. Sensitivity disclosures include, in particular,
the impact of a 20% reduction in forecast revenues.
Contingent consideration
Liabilities for contingent consideration have been recognised on certain business combinations, which are measured at fair value at acquisition and remeasured at fair value through profit and loss at each reporting date.
The amounts of contingent consideration ultimately payable depend on several factors, including the progress of certain of the oil and gas properties acquired and the achievement of certain production and commodity price thresholds.
Management has estimated the fair value as the aggregate value of each element of the contingent consideration in each case using an appropriate valuation technique, taking into account the likelihood of occurrence of each contingent
event and the net present value of the amount potentially payable. Where applicable, risking assumptions applied in the measurement of contingent consideration were consistent with those applied in the fair valuation of the related oil
and gas properties.
A 20% decrease in the probability of a trigger event occurring and hence a payment being due, with all other assumptions held constant, would result in a decrease in contingent consideration of $84.2 million (2023: $97.1 million).
Whereas a 20% increase in probability of a trigger event occurring, with all other assumptions held constant, would result in an increase in contingent consideration of $80.4 million (2023: $84.1 million).
Decommissioning provision estimates
Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells.
Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements, technology and price levels,
the carrying amounts of decommissioning provisions are reviewed on a regular basis. The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. For operated assets, cost estimates
are based on management\u2019s assessment of work programmes (including durations) and supply chain conditions including, amongst other factors, applicable vessel and rig rates and durations. For non-operated assets, cost estimates are
arrived at by management\u2019s review of the basis of estimates as provided by the respective operators.
While the Group uses its best estimates and judgement, actual results could differ from these estimates. Expected timing of expenditure can also change, for example in response to changes in laws and regulations or their interpretation,
and/or due to changes in commodity prices. The payment dates are uncertain and depend on the production lives of the respective fields. Management does not expect any reasonable change in the expected timing of decommissioning
to have a material effect on the decommissioning provisions, assuming cash flows remain unchanged. Decommissioning costs are expected to be incurred over the next 40 years. Whereas previously the Group used a uniform nominal
discount rate over all future years, it has now revised its methodology to use a short-to-medium-term nominal discount rate and a long-term nominal discount rate. The Group uses a nominal discount rate of 4.38% for the first five years
and 4.86% thereafter (31 December 2023: 4.60% for all years), based on the average risk-free rate over the second half of 2024, to discount the estimated costs. The inflation rate applied to estimated costs is 2.0% (2023: 2.0%).
Given the long-term nature of the Group\u2019s decommissioning liabilities and the historic compounded inflation rates in the industry, management do not believe that the current short-term inflationary pressures will have a material
impact on the decommissioning liabilities of the Group. A reduction or an increase in this discount rate of 1% would increase or reduce the decommissioning liabilities by approximately $288 million or $247 million, respectively
(2023: $223 million or $188 million, respectively), and is not expected to have a material impact on the corresponding decommissioning reimbursement asset. For further details regarding the estimated value, inputs and assumptions
refer to note 23. Given the large number of variables involved, management consider that it is not practical to provide sensitivities for the various other individual assumptions but the aggregated impact of related changes in the next
12 months could be material .
Taxation estimates The Group\u2019s operations are subject to a number of specific tax rules which apply to exploration, development and production companies such as the Energy Profits Levy at 35% to 31 October 2024 and 38% thereafter, ring-fenced Corporation Tax at 30%, the Supplementary Charge of 10% and the application of investment allowances. In addition, the tax provision is prepared before the relevant companies have filed their tax returns with the relevant tax authorities and, significantly, before these have been agreed. As a result of these factors, the tax provision process necessarily involves the use of a number of judgements and estimates, including those required in calculating the effective tax rate. The Group recognises deferred tax assets on unused tax losses where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the likelihood of future taxable profits and the amount of deferred tax that can be recognised. Further details regarding the estimated value and related inputs are set out in note 28. The Group\u2019s deferred tax assets are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised, including as a result of Group re-organisations and asset transfers. In accordance with IAS 12 Income Taxes, the Group assesses the recoverability of its deferred tax assets at each period end. Consistent with the impairment sensitivity described above, as at 31 December 2024, a 20% reduction in future revenues, with all other assumptions held constant, would eliminate current headroom and result in a deferred tax asset derecognition of $284 million (2023: $304 million). It should be noted that mitigating actions are considered to be available to materially offset this impact. The $284 million (2023: $304 million) derecognition assumes that cash flows are equivalent to taxable profits and that any reorganisation required to utilise certain deferred tax assets does not result in a displacement of other balances. As disclosed in note 28, there are unrecognised allowances of up to circa $150 million that have no expiry date and could be recognised in future periods if future revenue from oil and gas activities increases and/or further actions are undertaken. Other areas of estimation The key assumptions concerning the future, and other sources of estimation uncertainty at the reporting period, that are not expected to cause a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below: Business combinations In 2024, the Group has made a material business combination \u2013 see note 17 for further details of the provisional purchase price allocation, including the assets and liabilities acquired and the goodwill arising on the transaction. This has been accounted for as a business combination under IFRS 3. The assets and liabilities identified in the purchase price allocation include oil and gas assets, decommissioning liabilities, deferred tax assets and liabilities, and working capital. The total consideration payable includes both the market value of new ordinary shares issued at the date of completion and a monetary settlement based on working capital movements, and certain other transactions such as dividend payments, between the economic effective date of 1 July 2024 and date of completion. The amount payable under this monetary settlement is discussed further in note 17. The calculation of the fair value of the oil and gas assets acquired requires the Group to estimate the future cash flows expected to arise from the assets of the acquired business using discounted cash flow models. Key assumptions and estimates include: commodity prices, discount rates and oil and gas reserves estimates. See above estimates in the impairment of oil and gas assets and goodwill section and estimates in oil and gas reserves and contingent resources section for further details regarding these assumptions. In addition, the Group has considered the value that a market participant would prescribe to prospective resources in determining the fair value of the oil and gas assets acquired. In determining the value of the deferred tax asset recognised on the Business Combination, the Group has also made assumptions in respect of the amount of tax losses brought forward, which will be available to offset against future taxable profits of the Group. Critical accounting judgements The following are the critical judgements, apart from those involving estimation (which are presented separately above), that the Directors have made in applying the Group\u2019s accounting policies and that have the most significant effect on the amounts recognised in the financial statements. Cambo and Rosebank carrying values Management has reviewed the pre-tax carrying value of the Cambo field of $391 million or post tax $234 million (2023: pre-tax $391 million or post-tax $234 million) and has concluded that due to the licence extension to 31 March 2026 and the detailed plans in place for final investment decision (FID), there are currently no indicators of impairment. The Group is actively engaging with potential farm-in partners to secure an aligned joint venture partnership that would help progress the project towards FID and assist in obtaining additional funding for the project. Management has submitted a request for a further 18 month extension of the licence to 30 September 2027 and to remove a milestone commitment that would otherwise require a joint venture partner to be secured by 31 March 2025, with the latter no longer considered by management as a commercial pre-requisite for the project to proceed to development following completion of the Eni UK Business Combination and the consequential increase in the scale and funding capability of the Group. A decision in respect of this request is expected by the North Sea Transition Authority (NSTA) by the end of the second quarter of 2025. Details of contingent consideration in respect of Cambo are set out in note 26. Similarly, management has reviewed the pre-tax carrying value of the Rosebank field of $617 million or post-tax $304 million (31 December 2023: pre-tax $413 million or post-tax $237 million). Although the first phase of the Rosebank development had been sanctioned by the NSTA, it was subject to Judicial Review proceedings. On 30 January 2025, the Court of Session ruled that this consent had been unlawfully given in relation to the sanctioning of the Rosebank field development and that a new consent application would be required, which included Scope 3 emissions. It did, however, permit the project to progress as planned whilst this new consent is sought from the Regulators but that no oil could be extracted without this new consent. Whilst the outcome of the Judicial Review could be construed as an indicator of impairment, management has no reason to believe that this further consent will not be forthcoming, and further management believe that the most likely outcome will be that the further consent will be granted and that the project will continue progressing as planned with first oil anticipated in 2026/27. As a result no impairment charge is required.", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-451": { "value": "Key sources of estimation uncertainty The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below. Estimates in oil and gas reserves and contingent resources The Group\u2019s estimates of oil and gas reserves and contingent resources, and the associated production forecasts, are used in the impairment testing of property plant and equipment and goodwill, in the measurement of depletion and decommissioning provisions, the measurement of certain elements of contingent consideration, the going concern assessment, the viability assessment and in the determination of whether deferred tax assets are recoverable. The business of the Group is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner. Estimates of oil and gas reserves and contingent resources require significant judgement. Factors such as the availability of geological and engineering data, reservoir performance data, drilling of new wells and estimates of future oil and gas prices all impact on the determination of the Group\u2019s estimates of its oil and gas reserves, which could result in different future production profiles affecting prospectively the discounted cash flows used in impairment testing. The Group\u2019s estimates of reserves and resource volumes used for accounting purposes are built up from historically-matched models for operated assets and principally from operators\u2019 estimates for non-operated assets. A review process is undertaken to compare the results of the Group\u2019s internal estimates to those of an independent consultant to understand any differences in underlying assumptions to ensure there are no significant unreconciled differences between the estimates. For the purposes of depletion and decommissioning estimates, the Group uses proved and probable reserves; and for the purposes of the impairment tests performed and deferred tax asset recoverability, the Group considers the same proved and probable reserves as well as risked resource volumes. These risking adjustments are reflective of management\u2019s assessment of technical and commercial factors that reflect the value considerations of a market participant. Changes in estimates of oil and gas reserves and resources resulting in different future production profiles will affect the discounted cash flows used in impairment testing, the anticipated date of decommissioning, the depletion charges in accordance with the unit of production method and the recoverability of deferred tax assets. The sensitivity of the Group\u2019s impairment tests and deferred tax recoverability assessments to key sources of estimation uncertainty, including reserves and resources, is discussed below. Estimates in impairment of oil and gas assets and goodwill Determination of whether the Group\u2019s oil and gas assets (note 15) or goodwill (note 18) have suffered any impairment requires an estimation of the recoverable amount of the CGU to which oil and gas assets and goodwill have been allocated. Projected future cash flows are used to determine a fair value less cost to sell to establish the recoverable amount. Key assumptions and estimates in the impairment models relate to: commodity prices that are based on an external view of forward curve prices that are considered to be a best estimate of what a market participant would use; discount rates which reflect management\u2019s estimate of a market participant post-tax weighted average cost of capital; and oil and gas reserves and resources on a risked basis as described above. Management\u2019s estimates of a market participant\u2019s view of pricing and discount rates are supplied by an independent consultant. The sensitivity of the Group\u2019s carrying amounts to these assumptions is illustrated by the impairments and reversals disclosed in note 19, and by the sensitivity disclosures in note 19. Sensitivity disclosures include, in particular, the impact of a 20% reduction in forecast revenues. Contingent consideration Liabilities for contingent consideration have been recognised on certain business combinations, which are measured at fair value at acquisition and remeasured at fair value through profit and loss at each reporting date. The amounts of contingent consideration ultimately payable depend on several factors, including the progress of certain of the oil and gas properties acquired and the achievement of certain production and commodity price thresholds. Management has estimated the fair value as the aggregate value of each element of the contingent consideration in each case using an appropriate valuation technique, taking into account the likelihood of occurrence of each contingent event and the net present value of the amount potentially payable. Where applicable, risking assumptions applied in the measurement of contingent consideration were consistent with those applied in the fair valuation of the related oil and gas properties. A 20% decrease in the probability of a trigger event occurring and hence a payment being due, with all other assumptions held constant, would result in a decrease in contingent consideration of $84.2 million (2023: $97.1 million). Whereas a 20% increase in probability of a trigger event occurring, with all other assumptions held constant, would result in an increase in contingent consideration of $80.4 million (2023: $84.1 million). Decommissioning provision estimates Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements, technology and price levels, the carrying amounts of decommissioning provisions are reviewed on a regular basis. The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. For operated assets, cost estimates are based on management\u2019s assessment of work programmes (including durations) and supply chain conditions including, amongst other factors, applicable vessel and rig rates and durations. For non-operated assets, cost estimates are arrived at by management\u2019s review of the basis of estimates as provided by the respective operators. While the Group uses its best estimates and judgement, actual results could differ from these estimates. Expected timing of expenditure can also change, for example in response to changes in laws and regulations or their interpretation, and/or due to changes in commodity prices. The payment dates are uncertain and depend on the production lives of the respective fields. Management does not expect any reasonable change in the expected timing of decommissioning to have a material effect on the decommissioning provisions, assuming cash flows remain unchanged. Decommissioning costs are expected to be incurred over the next 40 years. Whereas previously the Group used a uniform nominal discount rate over all future years, it has now revised its methodology to use a short-to-medium-term nominal discount rate and a long-term nominal discount rate. The Group uses a nominal discount rate of 4.38% for the first five years and 4.86% thereafter (31 December 2023: 4.60% for all years), based on the average risk-free rate over the second half of 2024, to discount the estimated costs. The inflation rate applied to estimated costs is 2.0% (2023: 2.0%). Given the long-term nature of the Group\u2019s decommissioning liabilities and the historic compounded inflation rates in the industry, management do not believe that the current short-term inflationary pressures will have a material impact on the decommissioning liabilities of the Group. A reduction or an increase in this discount rate of 1% would increase or reduce the decommissioning liabilities by approximately $288 million or $247 million, respectively (2023: $223 million or $188 million, respectively), and is not expected to have a material impact on the corresponding decommissioning reimbursement asset. For further details regarding the estimated value, inputs and assumptions refer to note 23. Given the large number of variables involved, management consider that it is not practical to provide sensitivities for the various other individual assumptions but the aggregated impact of related changes in the next 12 months could be material . Taxation estimates The Group\u2019s operations are subject to a number of specific tax rules which apply to exploration, development and production companies such as the Energy Profits Levy at 35% to 31 October 2024 and 38% thereafter, ring-fenced Corporation Tax at 30%, the Supplementary Charge of 10% and the application of investment allowances. In addition, the tax provision is prepared before the relevant companies have filed their tax returns with the relevant tax authorities and, significantly, before these have been agreed. As a result of these factors, the tax provision process necessarily involves the use of a number of judgements and estimates, including those required in calculating the effective tax rate. The Group recognises deferred tax assets on unused tax losses where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the likelihood of future taxable profits and the amount of deferred tax that can be recognised. Further details regarding the estimated value and related inputs are set out in note 28. The Group\u2019s deferred tax assets are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised, including as a result of Group re-organisations and asset transfers. In accordance with IAS 12 Income Taxes, the Group assesses the recoverability of its deferred tax assets at each period end. Consistent with the impairment sensitivity described above, as at 31 December 2024, a 20% reduction in future revenues, with all other assumptions held constant, would eliminate current headroom and result in a deferred tax asset derecognition of $284 million (2023: $304 million). It should be noted that mitigating actions are considered to be available to materially offset this impact. The $284 million (2023: $304 million) derecognition assumes that cash flows are equivalent to taxable profits and that any reorganisation required to utilise certain deferred tax assets does not result in a displacement of other balances. As disclosed in note 28, there are unrecognised allowances of up to circa $150 million that have no expiry date and could be recognised in future periods if future revenue from oil and gas activities increases and/or further actions are undertaken. ", "dimensions": { "concept": "ifrs-full:ExplanationOfAssumptionAboutFutureWithSignificantRiskOfResultingInMaterialAdjustments", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-407": { "value": "
4. Segmental reporting
The Group operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area, presently being the North Sea. The Group\u2019s segmental reporting structure
remained in place for all periods presented and is consistent with the way in which the Group\u2019s activities are reported to the Board and Chief Decision Making Officer. The Group\u2019s activities are considered to be an individual operating
segment due to the nature of the Group\u2019s operations being consistent, and such operations existing in a single geographical region that is covered by the same regulations.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-408": { "value": "
5. Revenue
2024 2023
$\u2019000 $\u2019000
Oil sales
1,176,274
1,329,751
Gas sales
598,962
658,659
Condensate sales
46,437
48,789
Other income
30,000
32,341
Realised gains/(losses) on oil derivative contracts
2,572
(31,676)
Put premiums on oil derivative instruments
(1,696)
(11,850)
Realised gains on gas derivative contracts
132,550
297,387
Put premiums on gas derivative instruments
(3,240)
(3,590)
1,981,859
2,319,811
The majority of payment terms are on a specified monthly date, as detailed in the initial contract. Otherwise, payment is due within 30 days of the invoice date. No significant judgements have been made in determining the timing of
satisfaction of performance obligations, the transaction prices and the amounts allocated to performance obligations. Other income relates to tariff income receivable in the year.
Revenue from two customers exceeded 10% of the Group\u2019s consolidated revenue arising from hydrocarbon sales for the year ended 31 December 2024, representing $1,284 million and $420 million of revenue, respectively
(2023: two customers representing $1,296 million and $436 million of revenue, respectively). It should be noted that the second largest customer in both 2024 and 2023 is now a related party and further details of related party
transactions are set out in note 32.
Revenue from contracts with customers derives largely from customers within a single geographical region, being the United Kingdom. Revenue from contracts with customers outside of the United Kingdom is immaterial and is,
therefore, not disclosed separately.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-452": { "value": "5. Revenue
2024 2023
$\u2019000 $\u2019000
Oil sales
1,176,274
1,329,751
Gas sales
598,962
658,659
Condensate sales
46,437
48,789
Other income
30,000
32,341
Realised gains/(losses) on oil derivative contracts
2,572
(31,676)
Put premiums on oil derivative instruments
(1,696)
(11,850)
Realised gains on gas derivative contracts
132,550
297,387
Put premiums on gas derivative instruments
(3,240)
(3,590)
1,981,859
2,319,811
The majority of payment terms are on a specified monthly date, as detailed in the initial contract. Otherwise, payment is due within 30 days of the invoice date. No significant judgements have been made in determining the timing of satisfaction of performance obligations, the transaction prices and the amounts allocated to performance obligations. Other income relates to tariff income receivable in the year. Revenue from two customers exceeded 10% of the Group\u2019s consolidated revenue arising from hydrocarbon sales for the year ended 31 December 2024, representing $1,284 million and $420 million of revenue, respectively (2023: two customers representing $1,296 million and $436 million of revenue, respectively). It should be noted that the second largest customer in both 2024 and 2023 is now a related party and further details of related party transactions are set out in note 32. Revenue from contracts with customers derives largely from customers within a single geographical region, being the United Kingdom. Revenue from contracts with customers outside of the United Kingdom is immaterial and is, therefore, not disclosed separately.", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-479": { "value": "Revenue from two customers exceeded 10% of the Group\u2019s consolidated revenue arising from hydrocarbon sales for the year ended 31 December 2024, representing $1,284 million and $420 million of revenue, respectively (2023: two customers representing $1,296 million and $436 million of revenue, respectively). It should be noted that the second largest customer in both 2024 and 2023 is now a related party and further details of related party transactions are set out in note 32. ", "dimensions": { "concept": "ifrs-full:DisclosureOfSegmentsMajorCustomersExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-409": { "value": "
6. Cost of sales
2024 2023
$\u2019000 $\u2019000
Movement in oil and gas inventory
84,193
20,582
Operating costs of hydrocarbon activities
(617,919)
(576,660)
Materials inventory provision
(3,568)
(16,268)
Royalties
(2,135)
(4,364)
Depreciation on right-of-use assets (note 15)
(26,819)
(42,648)
Depletion, depreciation and amortisation (note 15)
(573,397)
(697,652)
(1,139,645)
(1,317,010)
Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds a 100% interest in the Stella and Harrier fields.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-478": { "value": "6. Cost of sales
2024 2023
$\u2019000 $\u2019000
Movement in oil and gas inventory
84,193
20,582
Operating costs of hydrocarbon activities
(617,919)
(576,660)
Materials inventory provision
(3,568)
(16,268)
Royalties
(2,135)
(4,364)
Depreciation on right-of-use assets (note 15)
(26,819)
(42,648)
Depletion, depreciation and amortisation (note 15)
(573,397)
(697,652)
(1,139,645)
(1,317,010)
Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds a 100% interest in the Stella and Harrier fields. 7. Administrative expenses
2024 2023
$\u2019000 $\u2019000
Administrative expenses, excluding transaction costs
(40,977)
(34,259)
Transaction costs
(16,303)
\u2013
(57,280)
(34,259)
Transactions costs in 2024 relate to the Eni UK Business Combination. Further details of the Business Combination can be found in note 17. The total employee benefit expenses which are either capitalised or included in cost of sales, pre-licence exploration and evaluation expenses and administrative expenses are noted below.
2023
2024 Restated
Employee benefit expenses $\u2019000 $\u2019000
Wages and salaries
(103,156)
(93,009)
Share-based payment charges (note 33)
(6,114)
(16,369)
Social security costs
(11,561)
(10,770)
Pension costs
(11,936)
(9,997)
(132,767)
(130,145)
Wages and salaries costs of $104.0 million and social security costs of $12.3 million disclosed in the 2023 Annual Report and Accounts incorrectly included one-off transactions in respect of the MEP (see note 33) and certain other Executive share options, which had already been included in the share-based payments charge line. Comparatives for 2023 have been restated to exclude these. Disclosures on Directors\u2019 remuneration, share options, long-term incentive schemes and pension entitlements required by the Companies Act 2006 are contained in the tables and notes within the Remuneration Committee report on pages 136 to 161. Directors\u2019 emoluments in aggregate were $4.4 million (2023: $13.4 million). The average number of employees during each year was as follows:
2024
2023
Onshore and administrative
374
316
Offshore
327
283
701
599
2024 2023
Audit fees $\u2019000 $\u2019000
Fees payable to the Company\u2019s auditor for audit of the Company\u2019s financial statements
2,464
1,286
Audit of the Company\u2019s subsidiaries pursuant to legislation
407
326
Non-audit services provided by the auditors
637
205
3,508
1,817
Non-audit services provided by the auditors for the year ended 31 December 2024 comprise audit-related assurance services of $175k (2023: $205k), other assurance services of $462k (2023: $nil) relating to work on the Offering Memorandum in respect of the refinancing and in relation to certain other refinancing options. In addition to the above figures, additional audit fees of $228k were charged during 2024 relating to the finalisation of prior period group and subsidiary audits.", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-453": { "value": "
2024 2023
$\u2019000 $\u2019000
Movement in oil and gas inventory
84,193
20,582
Operating costs of hydrocarbon activities
(617,919)
(576,660)
Materials inventory provision
(3,568)
(16,268)
Royalties
(2,135)
(4,364)
Depreciation on right-of-use assets (note 15)
(26,819)
(42,648)
Depletion, depreciation and amortisation (note 15)
(573,397)
(697,652)
(1,139,645)
(1,317,010)
Right-of-use Development and Other
operating assets production assets fixed assets Total
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Cost
At 1 January 2023
98,927
7,112,652
45,912
7,257,491
Additions
26,468
358,361
1,728
386,557
Transfers from exploration and evaluation assets (note 14)
30,774
348,527
\u2013
379,301
Change in decommissioning estimates (note 23)
\u2013
157,224
\u2013
157,224
At 31 December 2023 and 1 January 2024
156,169
7,976,764
47,640
8,180,573
Additions
136,264
483,511
545
620,320
Business combinations (note 17)
18,673
997,937
\u2013
1,016,610
Change in decommissioning estimates (note 23)
\u2013
54,581
\u2013
54,581
At 31 December 2024
311,106
9,512,793
48,185
9,872,084
Depletion, depreciation, amortisation and impairment
At 1 January 2023
(42,867)
(3,555,656)
(24,072)
(3,622,595)
Depletion, depreciation and amortisation charge for the year
(42,648)
(693,573)
(4,079)
(740,300)
Impairment charge (note 19)
\u2013
(559,472)
\u2013
(559,472)
At 31 December 2023 and 1 January 2024
(85,515)
(4,808,701)
(28,151)
(4,922,367)
Depletion, depreciation and amortisation charge for the year
(26,819)
(568,139)
(5,258)
(600,216)
Impairment charge (note 19)
\u2013
(161,066)
\u2013
(161,066)
At 31 December 2024
(112,334)
(5,537,906)
(33,409)
(5,683,649)
Net book value at 31 December 2023
70,654
3,168,063
19,489
3,258,206
Net book value at 31 December 2024
198,772
3,974,887
14,776
4,188,435
", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-410": { "value": "
7. Administrative expenses
2024 2023
$\u2019000 $\u2019000
Administrative expenses, excluding transaction costs
(40,977)
(34,259)
Transaction costs
(16,303)
\u2013
(57,280)
(34,259)
Transactions costs in 2024 relate to the Eni UK Business Combination. Further details of the Business Combination can be found in note 17.
The total employee benefit expenses which are either capitalised or included in cost of sales, pre-licence exploration and evaluation expenses and administrative expenses are noted below.
2023
2024 Restated
Employee benefit expenses $\u2019000 $\u2019000
Wages and salaries
(103,156)
(93,009)
Share-based payment charges (note 33)
(6,114)
(16,369)
Social security costs
(11,561)
(10,770)
Pension costs
(11,936)
(9,997)
(132,767)
(130,145)
Wages and salaries costs of $104.0 million and social security costs of $12.3 million disclosed in the 2023 Annual Report and Accounts incorrectly included one-off transactions in respect of the MEP (see note 33) and certain other
Executive share options, which had already been included in the share-based payments charge line. Comparatives for 2023 have been restated to exclude these.
Disclosures on Directors\u2019 remuneration, share options, long-term incentive schemes and pension entitlements required by the Companies Act 2006 are contained in the tables and notes within the Remuneration Committee report
on pages 136 to 161. Directors\u2019 emoluments in aggregate were $4.4 million (2023: $13.4 million).
The average number of employees during each year was as follows:
2024
2023
Onshore and administrative
374
316
Offshore
327
283
701
599
2024 2023
Audit fees $\u2019000 $\u2019000
Fees payable to the Company\u2019s auditor for audit of the Company\u2019s financial statements
2,464
1,286
Audit of the Company\u2019s subsidiaries pursuant to legislation
407
326
Non-audit services provided by the auditors
637
205
3,508
1,817
Non-audit services provided by the auditors for the year ended 31 December 2024 comprise audit-related assurance services of $175k (2023: $205k), other assurance services of $462k (2023: $nil) relating to work on the Offering
Memorandum in respect of the refinancing and in relation to certain other refinancing options. In addition to the above figures, additional audit fees of $228k were charged during 2024 relating to the finalisation of prior period group
and subsidiary audits.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-454": { "value": "
2023
2024 Restated
Employee benefit expenses $\u2019000 $\u2019000
Wages and salaries
(103,156)
(93,009)
Share-based payment charges (note 33)
(6,114)
(16,369)
Social security costs
(11,561)
(10,770)
Pension costs
(11,936)
(9,997)
(132,767)
(130,145)
Wages and salaries costs of $104.0 million and social security costs of $12.3 million disclosed in the 2023 Annual Report and Accounts incorrectly included one-off transactions in respect of the MEP (see note 33) and certain other Executive share options, which had already been included in the share-based payments charge line. Comparatives for 2023 have been restated to exclude these. Disclosures on Directors\u2019 remuneration, share options, long-term incentive schemes and pension entitlements required by the Companies Act 2006 are contained in the tables and notes within the Remuneration Committee report on pages 136 to 161. Directors\u2019 emoluments in aggregate were $4.4 million (2023: $13.4 million). The average number of employees during each year was as follows:
2024
2023
Onshore and administrative
374
316
Offshore
327
283
701
599
", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-494": { "value": "
2023
2024 Restated
Employee benefit expenses $\u2019000 $\u2019000
Wages and salaries
(103,156)
(93,009)
Share-based payment charges (note 33)
(6,114)
(16,369)
Social security costs
(11,561)
(10,770)
Pension costs
(11,936)
(9,997)
(132,767)
(130,145)
", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-455": { "value": "
2024 2023
Audit fees $\u2019000 $\u2019000
Fees payable to the Company\u2019s auditor for audit of the Company\u2019s financial statements
2,464
1,286
Audit of the Company\u2019s subsidiaries pursuant to legislation
407
326
Non-audit services provided by the auditors
637
205
3,508
1,817
Non-audit services provided by the auditors for the year ended 31 December 2024 comprise audit-related assurance services of $175k (2023: $205k), other assurance services of $462k (2023: $nil) relating to work on the Offering Memorandum in respect of the refinancing and in relation to certain other refinancing options. In addition to the above figures, additional audit fees of $228k were charged during 2024 relating to the finalisation of prior period group and subsidiary audits.", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-411": { "value": "
8. Other gains and losses
2024 2023
$\u2019000 $\u2019000
Gain on financial instruments (note 30)
5,167
43,059
Fair value gains/(losses) on contingent consideration and accretion on deferred consideration (note 26)
27,317
(8,008)
Remeasurements of decommissioning reimbursement receivables
\u2013
5,645
Net foreign exchange
(6,124)
(1,673)
Settlement of historic claim relating to an acquisition
\u2013
50,068
26,360
89,091
On 12 February 2023, the Group reached agreement on the settlement of a historic claim relating to an acquisition. Under the terms of the agreement the Group received $50.1 million.
", "dimensions": { "concept": "ithacaenergyplc:DisclosureOfOtherGainsAndLosses", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-412": { "value": "
9. Finance costs and finance income
2024 2023
$\u2019000 $\u2019000
Loan interest and charges
(48,036)
(47,494)
Senior notes interest
(54,904)
(58,377)
Loan fee amortisation
(13,222)
(4,508)
Interest on lease liabilities (note 25)
(1,508)
(3,183)
Accretion on decommissioning liabilities less accretion on decommissioning reimbursements
(82,908)
(76,162)
Total finance costs
(200,578)
(189,724)
Finance income
11,164
5,688
Loan interest and charges includes a charge of $14.1 million in respect of the early repayment of the Senior Notes due 2026 and loan fee amortisation contains a charge of $7.9 million in relation to unamortised fees on the refinancing
of the RBL and Senior Notes. See note 20 for further details.
During the year to 31 December 2024, $5.8 million of interest was capitalised into qualifying assets (2023: $nil) at an interest rate of SOFR (subject to a minimum rate of 5%) plus a commercially agreed margin on the entirety of the
borrowings under the project capital expenditure facility (see note 20 for further details).
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-499": { "value": "9. Finance costs and finance income
2024 2023
$\u2019000 $\u2019000
Loan interest and charges
(48,036)
(47,494)
Senior notes interest
(54,904)
(58,377)
Loan fee amortisation
(13,222)
(4,508)
Interest on lease liabilities (note 25)
(1,508)
(3,183)
Accretion on decommissioning liabilities less accretion on decommissioning reimbursements
(82,908)
(76,162)
Total finance costs
(200,578)
(189,724)
Finance income
11,164
5,688
Loan interest and charges includes a charge of $14.1 million in respect of the early repayment of the Senior Notes due 2026 and loan fee amortisation contains a charge of $7.9 million in relation to unamortised fees on the refinancing of the RBL and Senior Notes. See note 20 for further details. During the year to 31 December 2024, $5.8 million of interest was capitalised into qualifying assets (2023: $nil) at an interest rate of SOFR (subject to a minimum rate of 5%) plus a commercially agreed margin on the entirety of the borrowings under the project capital expenditure facility (see note 20 for further details).", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-501": { "value": "9. Finance costs and finance income
2024 2023
$\u2019000 $\u2019000
Loan interest and charges
(48,036)
(47,494)
Senior notes interest
(54,904)
(58,377)
Loan fee amortisation
(13,222)
(4,508)
Interest on lease liabilities (note 25)
(1,508)
(3,183)
Accretion on decommissioning liabilities less accretion on decommissioning reimbursements
(82,908)
(76,162)
Total finance costs
(200,578)
(189,724)
Finance income
11,164
5,688
Loan interest and charges includes a charge of $14.1 million in respect of the early repayment of the Senior Notes due 2026 and loan fee amortisation contains a charge of $7.9 million in relation to unamortised fees on the refinancing of the RBL and Senior Notes. See note 20 for further details. During the year to 31 December 2024, $5.8 million of interest was capitalised into qualifying assets (2023: $nil) at an interest rate of SOFR (subject to a minimum rate of 5%) plus a commercially agreed margin on the entirety of the borrowings under the project capital expenditure facility (see note 20 for further details).", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-495": { "value": "9. Finance costs and finance income
2024 2023
$\u2019000 $\u2019000
Loan interest and charges
(48,036)
(47,494)
Senior notes interest
(54,904)
(58,377)
Loan fee amortisation
(13,222)
(4,508)
Interest on lease liabilities (note 25)
(1,508)
(3,183)
Accretion on decommissioning liabilities less accretion on decommissioning reimbursements
(82,908)
(76,162)
Total finance costs
(200,578)
(189,724)
Finance income
11,164
5,688
Loan interest and charges includes a charge of $14.1 million in respect of the early repayment of the Senior Notes due 2026 and loan fee amortisation contains a charge of $7.9 million in relation to unamortised fees on the refinancing of the RBL and Senior Notes. See note 20 for further details. During the year to 31 December 2024, $5.8 million of interest was capitalised into qualifying assets (2023: $nil) at an interest rate of SOFR (subject to a minimum rate of 5%) plus a commercially agreed margin on the entirety of the borrowings under the project capital expenditure facility (see note 20 for further details).", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-480": { "value": "9. Finance costs and finance income
2024 2023
$\u2019000 $\u2019000
Loan interest and charges
(48,036)
(47,494)
Senior notes interest
(54,904)
(58,377)
Loan fee amortisation
(13,222)
(4,508)
Interest on lease liabilities (note 25)
(1,508)
(3,183)
Accretion on decommissioning liabilities less accretion on decommissioning reimbursements
(82,908)
(76,162)
Total finance costs
(200,578)
(189,724)
Finance income
11,164
5,688
Loan interest and charges includes a charge of $14.1 million in respect of the early repayment of the Senior Notes due 2026 and loan fee amortisation contains a charge of $7.9 million in relation to unamortised fees on the refinancing of the RBL and Senior Notes. See note 20 for further details. During the year to 31 December 2024, $5.8 million of interest was capitalised into qualifying assets (2023: $nil) at an interest rate of SOFR (subject to a minimum rate of 5%) plus a commercially agreed margin on the entirety of the borrowings under the project capital expenditure facility (see note 20 for further details).", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-456": { "value": "9. Finance costs and finance income
2024 2023
$\u2019000 $\u2019000
Loan interest and charges
(48,036)
(47,494)
Senior notes interest
(54,904)
(58,377)
Loan fee amortisation
(13,222)
(4,508)
Interest on lease liabilities (note 25)
(1,508)
(3,183)
Accretion on decommissioning liabilities less accretion on decommissioning reimbursements
(82,908)
(76,162)
Total finance costs
(200,578)
(189,724)
Finance income
11,164
5,688
Loan interest and charges includes a charge of $14.1 million in respect of the early repayment of the Senior Notes due 2026 and loan fee amortisation contains a charge of $7.9 million in relation to unamortised fees on the refinancing of the RBL and Senior Notes. See note 20 for further details. During the year to 31 December 2024, $5.8 million of interest was capitalised into qualifying assets (2023: $nil) at an interest rate of SOFR (subject to a minimum rate of 5%) plus a commercially agreed margin on the entirety of the borrowings under the project capital expenditure facility (see note 20 for further details).", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-413": { "value": "
10. Earnings per share
The calculation of basic earnings per share is based on the profit after tax and the weighted average number of ordinary shares in issue during the year. Basic and diluted earnings per share are calculated as follows:
2023
2024
Restated
1
$\u2019000 $\u2019000
Earnings for the year:
Earnings for the purpose of basic and diluted earnings per share
153,153
292,554
Number of shares (million)
Weighted average number of ordinary shares for the purpose of basic earnings per share
1,164.3
1,006.7
Dilutive potential ordinary shares
10.5
12.7
Weighted average number of ordinary shares for the purpose of diluted earnings per share
1,174.8
1,019.4
Earnings per share (cents)
Basic
13.2
29.1
Diluted
13.0
28.7
1 See note 2.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-414": { "value": "
11. Trade and other receivables and decommissioning reimbursements
2024 2023
Current $\u2019000 $\u2019000
Trade receivables
18,962
19,968
Other receivables
23,042
24,369
Joint operations receivables
105,999
91,960
Accrued income
269,611
197,993
417,614
334,290
Materially all trade and other receivables, including receivables from joint operations are not overdue by more than 90 days. The credit risk associated with trade receivables, accrued income and other receivables is considered to be
insignificant. No ECL has been recognised in the current or prior year.
Accrued income mainly comprises amounts due, but not yet invoiced, for the sale of oil and gas.
2024 2023
Non-current $\u2019000 $\u2019000
Decommissioning reimbursements
144,185
165,064
2024 2023
Current $\u2019000 $\u2019000
Decommissioning reimbursements
23,175
30,417
Movements on decommissioning reimbursements were as follows:
2024 2023
$\u2019000 $\u2019000
At 1 January
195,481
200,825
Accretion net of tax at 30%
7,370
7,536
Reimbursements received
(22,450)
(22,101)
Change in reimbursement estimates
(13,041)
9,221
At 31 December
167,360
195,481
The decommissioning reimbursements represent the equal and opposite of decommissioning liabilities (note 23), net of tax, associated with the Heather and Strathspey fields and relates to a contractual agreement as part of the
CNSL acquisition. As part of the terms of the acquisition of what is now Ithaca Oil and Gas Limited (IOGL), Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations
of IOGL in relation to these interests. The Group pays the liabilities in respect of Heather and Strathspey and then receives full reimbursement from Chevron.
As these payments are virtually certain, they have been accounted for under IAS 37 as a reimbursement asset.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-457": { "value": "
2024 2023
Current $\u2019000 $\u2019000
Trade receivables
18,962
19,968
Other receivables
23,042
24,369
Joint operations receivables
105,999
91,960
Accrued income
269,611
197,993
417,614
334,290
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-458": { "value": "
2024 2023
Non-current $\u2019000 $\u2019000
Decommissioning reimbursements
144,185
165,064
2024 2023
Current $\u2019000 $\u2019000
Decommissioning reimbursements
23,175
30,417
Movements on decommissioning reimbursements were as follows:
2024 2023
$\u2019000 $\u2019000
At 1 January
195,481
200,825
Accretion net of tax at 30%
7,370
7,536
Reimbursements received
(22,450)
(22,101)
Change in reimbursement estimates
(13,041)
9,221
At 31 December
167,360
195,481
", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-415": { "value": "
12. Prepayments
2024 2023
Current $\u2019000 $\u2019000
Prepayments
40,572
34,355
Decommissioning securities
1,638
3,323
42,210
37,678
", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-417": { "value": "
13. Inventories
2024 2023
Current $\u2019000 $\u2019000
Hydrocarbon underlift
171,795
60,427
Materials inventories
175,514
125,674
Provision for obsolete materials inventory
(63,470)
(35,605)
283,839
150,496
", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-416": { "value": "
14. Exploration and evaluation assets
$\u2019000
At 1 January 2023
775,773
Additions
165,516
Transfers to right-of-use operating assets and development and production assets (note 15)
(379,301)
Write-offs/relinquishments
(13,634)
At 31 December 2023 and 1 January 2024
548,354
Additions
36,327
Change in decommissioning estimates (note 23)
4,390
Business combinations (note 17)
48,000
Write-offs/relinquishments
(24,557)
At 31 December 2024
612,514
Following completion of geotechnical evaluation activity, certain North Sea licences were declared unsuccessful and certain prospects were declared non-commercial. This resulted in the carrying value of these licences being fully
written-off to $nil with $24.6 million being expensed in the year to 31 December 2024 (2023: $13.6 million).
The transfers from exploration and evaluation assets to right-of-use assets and development and production assets in 2023 relates to the Rosebank field.
The principal component of exploration and evaluation assets at 31 December 2024 is the Cambo field with a pre-tax carrying value of $391 million (2023: $391 million).
", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-418": { "value": "
15. Property, plant and equipment
Right-of-use Development and Other
operating assets production assets fixed assets Total
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Cost
At 1 January 2023
98,927
7,112,652
45,912
7,257,491
Additions
26,468
358,361
1,728
386,557
Transfers from exploration and evaluation assets (note 14)
30,774
348,527
\u2013
379,301
Change in decommissioning estimates (note 23)
\u2013
157,224
\u2013
157,224
At 31 December 2023 and 1 January 2024
156,169
7,976,764
47,640
8,180,573
Additions
136,264
483,511
545
620,320
Business combinations (note 17)
18,673
997,937
\u2013
1,016,610
Change in decommissioning estimates (note 23)
\u2013
54,581
\u2013
54,581
At 31 December 2024
311,106
9,512,793
48,185
9,872,084
Depletion, depreciation, amortisation and impairment
At 1 January 2023
(42,867)
(3,555,656)
(24,072)
(3,622,595)
Depletion, depreciation and amortisation charge for the year
(42,648)
(693,573)
(4,079)
(740,300)
Impairment charge (note 19)
\u2013
(559,472)
\u2013
(559,472)
At 31 December 2023 and 1 January 2024
(85,515)
(4,808,701)
(28,151)
(4,922,367)
Depletion, depreciation and amortisation charge for the year
(26,819)
(568,139)
(5,258)
(600,216)
Impairment charge (note 19)
\u2013
(161,066)
\u2013
(161,066)
At 31 December 2024
(112,334)
(5,537,906)
(33,409)
(5,683,649)
Net book value at 31 December 2023
70,654
3,168,063
19,489
3,258,206
Net book value at 31 December 2024
198,772
3,974,887
14,776
4,188,435
The transfers from exploration and evaluation assets to right-of-use operating assets and development and production assets in 2023 relates to the Rosebank development following consent being granted for the development by the
North Sea Transition Authority (NSTA) on 27 September 2023. Subsequently, this decision was the subject of a Judicial Review and on 30 January 2025, the Court of Session ruled that consent had been unlawfully given in relation
to the sanctioning of the Rosebank field development and that a new consent application would be required which included Scope 3 emissions. It did, however, permit the project to progress as planned whilst this new approval is sought
(see note 3 for further details). At the point of transfer in 2023, the Rosebank assets were tested for impairment and the recoverable amount exceeded the carrying value of the field.
Additions to right-of-use assets in the year to 31 December 2024 and the year to 31 December 2023 principally relate to modifications to the Rosebank FPSO and will begin to be depreciated on commencement of production.
The related lease will commence on delivery of the FPSO to the joint venture partners at first oil, which is currently anticipated to be 2026/27.
Other fixed assets include buildings, computer equipment, office equipment and furniture and fittings.
", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-419": { "value": "
16. Interests in joint operations
The contractual agreement for the licence interests in which the Group has an investment do not typically convey control of the underlying joint arrangement to any one party, even where one party has a greater than 50% equity
ownership of the area of interest.
The Group\u2019s material joint operations as at 31 December are as follows:
Group net % interest
Block
Licence
Field/discovery name
Operator
2024
2023
9/11c
P.979
Mariner
Equinor UK Limited
8.89%
8.89%
9/11b
P.726
Mariner
Equinor UK Limited
8.89%
8.89%
30/2c
P.672
Jade
Chrysaor Petroleum Company U.K. Limited
32.50%
25.50%
22/30c and 29/5c
P.666
Elgin-Franklin
TotalEnergies E&P UK Limited
27.95%
6.09%
15/29b
P.590
Callanish
Chrysaor Production (U.K.) Limited
20.00%
20.00%
204/25a
P.559
Schiehallion
BP Exploration Operating Company Limited
35.30%
35.30%
204/19b and 204/20b
P.556
Suilven
Ithaca SP E&P Limited
50.00%
50.00%
29/5b
P.362
Elgin-Franklin
TotalEnergies E&P UK Limited
27.95%
6.09%
21/4a
P.347
Callanish
Chrysaor Production (U.K.) Limited
13.70%
13.70%
16/27b
P.345
Britannia
Ithaca MA Limited
35.75%
35.75%
9/11a
P.335
Mariner
Equinor UK Limited
8.89%
8.89%
13/22a
P.324
Captain
Ithaca SP E&P Limited
85.00%
85.00%
22/18a
P.292
Arbroath, Arkwright, Carnoustie, Wood
Repsol Resources UK Limited
41.03%
41.03%
22/17s, 22/22a and 22/23a
P.291
Arbroath, Arkwright, Brechin, Carnoustie, Cayley, Shaw
Repsol Resources UK Limited
41.03%
41.03%
23/26b
P.264
Erskine
Ithaca Energy (UK) Limited
50.00%
50.00%
9/11d and 9/12b
P.2508
Mariner
Equinor UK Limited
8.89%
8.89%
9/11g
P.2151
Mariner
Equinor UK Limited
8.89%
8.89%
16/26a A-ALB
P.213
Alba
Ithaca Oil and Gas Limited
36.67%
36.67%
16/26a B-BRI
P.213
Britannia
Ithaca MA Limited
33.17%
33.17%
16/26a
P.213
N/A
Ithaca Oil and Gas Limited
34.50%
34.50%
3/7a
P.203
Columba E
CNR International (U.K.) Limited
20.00%
20.00%
3/8a and 3/8a
P.199
Columba B/D
CNR International (U.K.) Limited
5.60%
5.60%
22/30b
P.188
Elgin-Franklin
TotalEnergies E&P UK Limited
27.95%
6.09%
Group net % interest
Block
Licence
Field/discovery name
Operator
2024
2023
15/18b
P.2158
Marigold
1
Ithaca Oil and Gas Limited
100.00%
100.00%
21/20a
P.185
Cook
Ithaca SP E&P Limited
61.35%
61.35%
8/15a
P.1758
Mariner
Equinor UK Limited
8.89%
8.89%
30/7b
P.1589
Jade
Chrysaor Petroleum U.K. Limited
32.50%
25.50%
30/1f
P.1588
Vorlich
2
Ithaca MA Limited
100.00%
100.00%
30/1c
P.363
Vorlich
Ithaca MA Limited
34.00%
34.00%
205/2a
P.1272
Rosebank
Equinor UK Limited
20.00%
20.00%
205/1a
P.1191
Rosebank
Equinor UK Limited
20.00%
20.00%
15/29a
P.119
Alder
Ithaca Energy (UK) Limited
73.68%
73.68%
15/29a
P.119
Britannia
Ithaca MA Limited
75.00%
75.00%
21/3a
P.118
Brodgar
Chrysaor Production (U.K.) Limited
25.00%
25.00%
23/22a
P.111
Pierce
Enterprise Oil Limited
34.01%
34.01%
15/30a
P.103
Britannia
Chrysaor Production (U.K.) Limited
33.03%
33.03%
21/5a
P.103
Enochdhu
Chrysaor Production (U.K.) Limited
50.00%
50.00%
213/26b and 213/27a
P.1026
Rosebank
Equinor UK Limited
20.00%
20.00%
23/26a
P.057
Erskine
Ithaca Energy (UK) Limited
50.00%
50.00%
22/18n
P.020
Montrose
Repsol Resources UK Limited
41.03%
41.03%
22/17n, 22/17s, 22/22a and 22/23a
P.019
Godwin, Montrose
Repsol Resources UK Limited
41.03%
41.03%
30/11a and 30/12d
P.1820
Isabella
Total Energies E&P North Sea UK Limited
72.50%
10.00%
204/8, 204/9c, 204/10c, 204/13, 204/14d
P.2403
Tornado
Ithaca SP E&P Limited
50.00%
50.00%
and 204/15
30/7a and 30/12a
P.032
Judy/Joanne
Chrysaor Petroleum Company U.K. Limited
33.00%
\u2013
30/7c
P.2221
Judy
Chrysaor Petroleum Company U.K. Limited
33.00%
\u2013
30/13d A
P.079
Judy
Chrysaor Petroleum Company U.K. Limited
15.00%
\u2013
30/6a
P.11
Jasmine
Chrysaor Petroleum Company U.K. Limited
33.00%
\u2013
29/4d
P.752
Glenelg
TotalEnergies E&P UK Limited
8.00%
\u2013
22/29b
P.2613
Glenelg Protection
TotalEnergies E&P UK Limited
32.14%
\u2013
30/20a
P.2220
Tommeliten
ConocoPhillips (U.K.) Holdings Limited
0.07%
\u2013
30/13e
P.2456
Talbot
Harbour Energy Limited
33.00%
\u2013
Group net % interest
Block
Licence
Field/discovery name
Operator
2024
2023
30/7d and 30/8a
P.2399
Judy East
Chrysaor Petroleum Company U.K. Limited
33.00%
\u2013
N/A
Pipeline
GAEL
INEOS FPS Limited
10.23%
\u2013
N/A
Pipeline
SEAL
TotalEnergies E&P UK Limited
21.87%
\u2013
44/11a and 44/12a
P.1055
Cygnus
Ithaca (NE) E&P Limited
38.75%
\u2013
22/29c
P.1622
Seagull
BP Exploration Operating Company Limited
35.00%
\u2013
47/14b
P.614
Juliet
Ithaca (NE) E&P Limited
81.00%
\u2013
44/24a
P.611
Minke
Ithaca (NE) E&P Limited
15.56%
\u2013
44/29b
P.454/P.611
Orca UK
Ithaca (NE) E&P Limited
15.56%
\u2013
44/19b
P.1139
Cameron
Tullow Limited
27.50%
\u2013
N/A
Pipeline
ETS
Kellas North Sea 2 Limited
25.00%
\u2013
36/30a, 42/3a, 42/4 and 42/5a
P.2133
Ossian
Spirit Energy Limited
30.00%
\u2013
42/2b, 42/3b, 42/7a, 42/8b and 42/9b
P.2126
Aurora
Spirit Energy Limited
30.00%
\u2013
44/11b
P.1731
Cepheus
Ithaca (NE) E&P Limited
34.48%
\u2013
43/14a
P.2430
Cavendish North
Spirit Energy Limited
40.00%
\u2013
43/15a, 44/11d and 44/12e
P.2429
Bennett
Ithaca (NE) E&P Limited
40.00%
\u2013
1 Marigold is a joint operation through a Unitisation and Unit Operating Agreement (UUOA) between Ithaca Oil and Gas Limited which owns licence P.2158, and Anasuria Hibiscus UK Limited and Caldera Petroleum (UK) Limited, which jointly own a licence for an adjacent block. Under the terms
of the UUOA, key decisions over the operations require the unanimous consent of Ithaca and certain other parties, such that joint control is present.
2 Vorlich is a joint operation through a UUOA between Ithaca MA Limited and bp, which extends across both Vorlich licences. Under the terms of the UUOA, key decisions effectively require unanimous approval by both parties.
In addition, the Group has the following wholly-owned licences and fields or discoveries which, although not currently joint operations, are presented for completeness:
Group net % interest
Block
Licence
Field/discovery name
Operator
2024
2023
22/1b
P.2373
F Block (Fotla and Fortriu)
Ithaca Oil and Gas Limited
100.00%
100.00%
29/10b
P.1665
Abigail
Ithaca SP E&P Limited
100.00%
100.00%
204/4a and 204/5a
P.1189
Cambo
Ithaca SP E&P Limited
100.00%
100.00%
204/9a and 204/10a
P.1028
Cambo
Ithaca SP E&P Limited
100.00%
100.00%
30/6a and 29/10a
P.011
Stella/Harrier
Ithaca Energy (UK) Limited
100.00%
100.00%
29/15, 30/11c, 30/16i and 30/6d
P.2622
J-Area West
Chrysaor Petroleum Company U.K. Limited
100.00%
\u2013
16/22b
P.2638
Quad 16
N/A
100.00%
\u2013
", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-481": { "value": "16. Interests in joint operations The contractual agreement for the licence interests in which the Group has an investment do not typically convey control of the underlying joint arrangement to any one party, even where one party has a greater than 50% equity ownership of the area of interest. The Group\u2019s material joint operations as at 31 December are as follows:
Group net % interest
Block
Licence
Field/discovery name
Operator
2024
2023
9/11c
P.979
Mariner
Equinor UK Limited
8.89%
8.89%
9/11b
P.726
Mariner
Equinor UK Limited
8.89%
8.89%
30/2c
P.672
Jade
Chrysaor Petroleum Company U.K. Limited
32.50%
25.50%
22/30c and 29/5c
P.666
Elgin-Franklin
TotalEnergies E&P UK Limited
27.95%
6.09%
15/29b
P.590
Callanish
Chrysaor Production (U.K.) Limited
20.00%
20.00%
204/25a
P.559
Schiehallion
BP Exploration Operating Company Limited
35.30%
35.30%
204/19b and 204/20b
P.556
Suilven
Ithaca SP E&P Limited
50.00%
50.00%
29/5b
P.362
Elgin-Franklin
TotalEnergies E&P UK Limited
27.95%
6.09%
21/4a
P.347
Callanish
Chrysaor Production (U.K.) Limited
13.70%
13.70%
16/27b
P.345
Britannia
Ithaca MA Limited
35.75%
35.75%
9/11a
P.335
Mariner
Equinor UK Limited
8.89%
8.89%
13/22a
P.324
Captain
Ithaca SP E&P Limited
85.00%
85.00%
22/18a
P.292
Arbroath, Arkwright, Carnoustie, Wood
Repsol Resources UK Limited
41.03%
41.03%
22/17s, 22/22a and 22/23a
P.291
Arbroath, Arkwright, Brechin, Carnoustie, Cayley, Shaw
Repsol Resources UK Limited
41.03%
41.03%
23/26b
P.264
Erskine
Ithaca Energy (UK) Limited
50.00%
50.00%
9/11d and 9/12b
P.2508
Mariner
Equinor UK Limited
8.89%
8.89%
9/11g
P.2151
Mariner
Equinor UK Limited
8.89%
8.89%
16/26a A-ALB
P.213
Alba
Ithaca Oil and Gas Limited
36.67%
36.67%
16/26a B-BRI
P.213
Britannia
Ithaca MA Limited
33.17%
33.17%
16/26a
P.213
N/A
Ithaca Oil and Gas Limited
34.50%
34.50%
3/7a
P.203
Columba E
CNR International (U.K.) Limited
20.00%
20.00%
3/8a and 3/8a
P.199
Columba B/D
CNR International (U.K.) Limited
5.60%
5.60%
22/30b
P.188
Elgin-Franklin
TotalEnergies E&P UK Limited
27.95%
6.09%
Group net % interest
Block
Licence
Field/discovery name
Operator
2024
2023
15/18b
P.2158
Marigold
1
Ithaca Oil and Gas Limited
100.00%
100.00%
21/20a
P.185
Cook
Ithaca SP E&P Limited
61.35%
61.35%
8/15a
P.1758
Mariner
Equinor UK Limited
8.89%
8.89%
30/7b
P.1589
Jade
Chrysaor Petroleum U.K. Limited
32.50%
25.50%
30/1f
P.1588
Vorlich
2
Ithaca MA Limited
100.00%
100.00%
30/1c
P.363
Vorlich
Ithaca MA Limited
34.00%
34.00%
205/2a
P.1272
Rosebank
Equinor UK Limited
20.00%
20.00%
205/1a
P.1191
Rosebank
Equinor UK Limited
20.00%
20.00%
15/29a
P.119
Alder
Ithaca Energy (UK) Limited
73.68%
73.68%
15/29a
P.119
Britannia
Ithaca MA Limited
75.00%
75.00%
21/3a
P.118
Brodgar
Chrysaor Production (U.K.) Limited
25.00%
25.00%
23/22a
P.111
Pierce
Enterprise Oil Limited
34.01%
34.01%
15/30a
P.103
Britannia
Chrysaor Production (U.K.) Limited
33.03%
33.03%
21/5a
P.103
Enochdhu
Chrysaor Production (U.K.) Limited
50.00%
50.00%
213/26b and 213/27a
P.1026
Rosebank
Equinor UK Limited
20.00%
20.00%
23/26a
P.057
Erskine
Ithaca Energy (UK) Limited
50.00%
50.00%
22/18n
P.020
Montrose
Repsol Resources UK Limited
41.03%
41.03%
22/17n, 22/17s, 22/22a and 22/23a
P.019
Godwin, Montrose
Repsol Resources UK Limited
41.03%
41.03%
30/11a and 30/12d
P.1820
Isabella
Total Energies E&P North Sea UK Limited
72.50%
10.00%
204/8, 204/9c, 204/10c, 204/13, 204/14d
P.2403
Tornado
Ithaca SP E&P Limited
50.00%
50.00%
and 204/15
30/7a and 30/12a
P.032
Judy/Joanne
Chrysaor Petroleum Company U.K. Limited
33.00%
\u2013
30/7c
P.2221
Judy
Chrysaor Petroleum Company U.K. Limited
33.00%
\u2013
30/13d A
P.079
Judy
Chrysaor Petroleum Company U.K. Limited
15.00%
\u2013
30/6a
P.11
Jasmine
Chrysaor Petroleum Company U.K. Limited
33.00%
\u2013
29/4d
P.752
Glenelg
TotalEnergies E&P UK Limited
8.00%
\u2013
22/29b
P.2613
Glenelg Protection
TotalEnergies E&P UK Limited
32.14%
\u2013
30/20a
P.2220
Tommeliten
ConocoPhillips (U.K.) Holdings Limited
0.07%
\u2013
30/13e
P.2456
Talbot
Harbour Energy Limited
33.00%
\u2013
Group net % interest
Block
Licence
Field/discovery name
Operator
2024
2023
30/7d and 30/8a
P.2399
Judy East
Chrysaor Petroleum Company U.K. Limited
33.00%
\u2013
N/A
Pipeline
GAEL
INEOS FPS Limited
10.23%
\u2013
N/A
Pipeline
SEAL
TotalEnergies E&P UK Limited
21.87%
\u2013
44/11a and 44/12a
P.1055
Cygnus
Ithaca (NE) E&P Limited
38.75%
\u2013
22/29c
P.1622
Seagull
BP Exploration Operating Company Limited
35.00%
\u2013
47/14b
P.614
Juliet
Ithaca (NE) E&P Limited
81.00%
\u2013
44/24a
P.611
Minke
Ithaca (NE) E&P Limited
15.56%
\u2013
44/29b
P.454/P.611
Orca UK
Ithaca (NE) E&P Limited
15.56%
\u2013
44/19b
P.1139
Cameron
Tullow Limited
27.50%
\u2013
N/A
Pipeline
ETS
Kellas North Sea 2 Limited
25.00%
\u2013
36/30a, 42/3a, 42/4 and 42/5a
P.2133
Ossian
Spirit Energy Limited
30.00%
\u2013
42/2b, 42/3b, 42/7a, 42/8b and 42/9b
P.2126
Aurora
Spirit Energy Limited
30.00%
\u2013
44/11b
P.1731
Cepheus
Ithaca (NE) E&P Limited
34.48%
\u2013
43/14a
P.2430
Cavendish North
Spirit Energy Limited
40.00%
\u2013
43/15a, 44/11d and 44/12e
P.2429
Bennett
Ithaca (NE) E&P Limited
40.00%
\u2013
1 Marigold is a joint operation through a Unitisation and Unit Operating Agreement (UUOA) between Ithaca Oil and Gas Limited which owns licence P.2158, and Anasuria Hibiscus UK Limited and Caldera Petroleum (UK) Limited, which jointly own a licence for an adjacent block. Under the terms of the UUOA, key decisions over the operations require the unanimous consent of Ithaca and certain other parties, such that joint control is present. 2 Vorlich is a joint operation through a UUOA between Ithaca MA Limited and bp, which extends across both Vorlich licences. Under the terms of the UUOA, key decisions effectively require unanimous approval by both parties. In addition, the Group has the following wholly-owned licences and fields or discoveries which, although not currently joint operations, are presented for completeness:
Group net % interest
Block
Licence
Field/discovery name
Operator
2024
2023
22/1b
P.2373
F Block (Fotla and Fortriu)
Ithaca Oil and Gas Limited
100.00%
100.00%
29/10b
P.1665
Abigail
Ithaca SP E&P Limited
100.00%
100.00%
204/4a and 204/5a
P.1189
Cambo
Ithaca SP E&P Limited
100.00%
100.00%
204/9a and 204/10a
P.1028
Cambo
Ithaca SP E&P Limited
100.00%
100.00%
30/6a and 29/10a
P.011
Stella/Harrier
Ithaca Energy (UK) Limited
100.00%
100.00%
29/15, 30/11c, 30/16i and 30/6d
P.2622
J-Area West
Chrysaor Petroleum Company U.K. Limited
100.00%
\u2013
16/22b
P.2638
Quad 16
N/A
100.00%
\u2013
The consolidated financial statements include the financial information of the Group, which comprises the Company and the subsidiaries listed in the following table:
% equity interest at 31 December
Registered office
Country of incorporation
2024
2023
Ithaca Energy (E&P) Limited
1
Jersey
100%
100%
Ithaca Energy (UK) Limited
2
Scotland
100%
100%
Ithaca Minerals (North Sea) Limited
2
Scotland
100%
100%
Ithaca Energy (Holdings) Limited
3
Bermuda
100%
100%
Ithaca Energy Holdings (UK) Limited
2
Scotland
100%
100%
Ithaca Energy (North Sea) PLC
2
Scotland
100%
100%
Ithaca Oil and Gas Limited
4
England and Wales
100%
100%
Ithaca Petroleum Ltd
4
England and Wales
100%
100%
Ithaca Causeway Limited
4
England and Wales
100%
100%
Ithaca Gamma Limited
4
England and Wales
100%
100%
Ithaca Alpha (NI) Limited
5
Northern Ireland
100%
100%
Ithaca Epsilon Limited
4
England and Wales
100%
100%
Ithaca Exploration Limited
4
England and Wales
100%
100%
Ithaca Petroleum EHF
6
Iceland
100%
100%
Ithaca Dorset Limited
4
England and Wales
100%
100%
Ithaca SP UK Limited
4
England and Wales
100%
100%
Ithaca GSA Holdings Limited
1
Jersey
100%
100%
Ithaca GSA Limited
1
Jersey
100%
100%
Ithaca Energy Developments UK Limited
4
England and Wales
100%
100%
FPF-1 Limited
7
Jersey
100%
100%
Ithaca MA Limited
4
England and Wales
100%
100%
Ithaca SP Bonds PLC
4
England and Wales
100%
100%
Ithaca SP Finance Limited
4
England and Wales
100%
100%
Ithaca SP (Holdings) Limited
4
England and Wales
100%
100%
Ithaca SP E&P Limited
4
England and Wales
100%
100%
Ithaca SP O&G Limited
4
England and Wales
100%
100%
Ithaca SPE Limited
4
England and Wales
100%
100%
Ithaca Zeta Limited
4
England and Wales
100%
100%
Ithaca EF Limited (formerly Eni Elgin/Franklin Limited)
4
England and Wales
100%
\u2013
Ithaca UKCS (formerly Eni UKCS Limited)
4
England and Wales
100%
\u2013
Ithaca (NE) E&P Limited (formerly Eni Energy E&P UK Limited)
4
England and Wales
100%
\u2013
Ithaca (NE) UKCS Limited (formerly Eni Energy E&P UKCS Limited)
4
England and Wales
100%
\u2013
Transactions between subsidiaries are eliminated on consolidation. Foot notes relating to table on preceding page: 1 47 Esplanade, St Helier, Jersey, JE1 0BD 2 13 Queen\u2019s Road, Aberdeen, Scotland AB15 4YL 3 Canon\u2019s Court, 22 Victoria Street, Hamilton HM 12, Bermuda 4 Pinsent Masons LLP, 1 Park Row, Leeds, England, LS1 5AB 5 Pinsent Masons LLP, The Soloist, 1 Lanyon Place, Belfast, BT1 3LP 6 Borgart\u00fani 26, 105 Reykjav\u00edk, Iceland 7 26 New Street, St Helier, Jersey, JE2 3RA 8 All of the above shares represent an ordinary class of shares. ", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-420": { "value": "
17. Business combinations
The Business Combination comprising 100% of each of Eni Elgin/Franklin Limited, Eni UKCS Limited, Eni Energy E&P Limited and Eni Energy E&P UKCS Limited, which established the Group with the largest resource base in
the UKCS, completed on 3 October 2024 with the Group issuing 639,360,174 new ordinary shares of \u00a30.01 each, representing at that time 38.7% of the enlarged Group. On that date, the opening market share price was \u00a31.0146
per share and the US Dollar exchange rate was $1.32768:\u00a31.00. The resulting share issuance consideration of $861 million will be augmented by a transaction cash amount primarily reflecting settlement for working capital balances,
including cash, at the date of completion together with certain other transactions between the economic effective date of 1 July 2024 and completion on 3 October 2024. The acquisition date of 3 October 2024 is the date the
group obtained control for accounting purposes. The amount payable under this mechanism has been agreed at $215.0 million of which $164.0 million is payable within 12 months and $51.0 million is payable in more than 12 months.
These amounts have been discounted at 4.33%. The discounted amount payable is $204.5 million (see note 26) and this is the amount of the cash consideration below.
The provisional fair values of the identifiable assets and liabilities as at the date of completion of the Business Combination were:
Total
2024
$\u2019000
Property, plant and equipment (note 15)
1,016,610
Exploration and evaluation assets (note 14)
48,000
Cash
107,475
Inventory
62,221
Trade and other receivables
178,037
Total assets excluding deferred tax
1,412,343
Trade and other payables
(281,680)
Decommissioning provisions (note 23)
(650,999)
Other provisions (note 24)
(34,865)
Lease liabilities (note 25)
(22,049)
Total liabilities excluding deferred tax
(989,593)
Deferred tax asset (note 28)
846,408
Deferred tax liability (note 28)
(549,062)
Total identifiable net assets at fair value
720,096
Consideration satisfied by the issue of new shares
861,259
Deferred consideration (note 26)
204,465
Total consideration
1,065,724
Goodwill arising on the Business Combination (note 18)
345,628
Net cash flows relating to the Business Combination during 2024, being cash acquired
107,475
From the date of the Business Combination, the Eni UK businesses contributed $290.1 million of revenue and $195.0 million of profit before tax in the year to 31 December 2024. Had the Business Combination completed on
1 January 2024, the Eni UK businesses would have contributed $1,014.0 million of revenue and $598.4 million of profit before tax for the 2024 financial year.
Business Combination related costs of $16.3 million (2023: $nil), comprising principally professional fees and other direct costs, were incurred in the year to 31 December 2024 and are included within 'administrative expenses' in note 7.
The fair values of the oil and gas assets and the intangible assets of the Eni UK businesses have been determined using valuation techniques based on discounted cash flows using forward curve commodity prices and estimates of long-
term commodity prices reflective of market conditions at the completion date, a discount rate based on observable market data and cost and production profiles generally consistent with the proved and probable reserves acquired with
each asset. The decommissioning liabilities recognised have been estimated based on internal engineering estimates for operated assets and operator cost estimates for non-operated assets, with reference to observable market data.
The goodwill generated on the Business Combination is largely the result of the IFRS requirement to recognise a deferred tax liability of $549.1 million on the fair value of the property, plant and equipment and exploration and
evaluation assets acquired through the Business Combination, despite these assets being recognised on a post tax basis.
", "dimensions": { "concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-421": { "value": "
18. Goodwill
2024 2023
$\u2019000 $\u2019000
Balance at 1 January
783,848
783,848
Additions (note 17)
345,628
\u2013
Balance at 31 December
1,129,476
783,848
The opening goodwill of $784 million relates to historic business combinations comprising principally Chevron in 2019 and Summit in 2022.
The goodwill on business combinations in the year to 31 December 2024 relates to the Eni UK businesses, as detailed in note 17.
The goodwill is not tax deductible on the Eni UK Business Combination.
Goodwill is monitored, and tested for impairment, at the operating segment level, being the North Sea (the entire Group portfolio of oil and gas assets). This is consistent with the operating segment view of the business, which is
presented to the Board and the Chief Decision Maker. The Group\u2019s activities are considered to be an individual operating segment due to the uniform nature of the Group\u2019s operations within a single geographical area, overseen by
the same management and subject to the same regulations. The fair value estimate is categorised as level 3 in the fair value hierarchy.
Annual impairment tests were performed at both 31 December 2024 and 31 December 2023. These reviews were carried out on a fair value less cost of disposal basis using risk-adjusted cash flow projections from the approved business
plans, including the same commodity prices, life of field cost profiles and production volumes used for impairment of oil and gas assets (see note 19), discounted at a post-tax discount rate of 10.0% (2023: 10.3%). Assumptions and
estimates in the Group impairment models are detailed in note 3. The recoverable amount of the North Sea CGU at 31 December 2024 was $418.8 million higher than its carrying amount, including goodwill, and hence no impairment
was recorded (2023 : $nil). An increase of 1% in the discount rate assumption would not result in a post-tax impairment of goodwill. Details of further sensitivities are provided in note 19.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-459": { "value": "18. Goodwill
2024 2023
$\u2019000 $\u2019000
Balance at 1 January
783,848
783,848
Additions (note 17)
345,628
\u2013
Balance at 31 December
1,129,476
783,848
The opening goodwill of $784 million relates to historic business combinations comprising principally Chevron in 2019 and Summit in 2022. The goodwill on business combinations in the year to 31 December 2024 relates to the Eni UK businesses, as detailed in note 17. The goodwill is not tax deductible on the Eni UK Business Combination. Goodwill is monitored, and tested for impairment, at the operating segment level, being the North Sea (the entire Group portfolio of oil and gas assets). This is consistent with the operating segment view of the business, which is presented to the Board and the Chief Decision Maker. The Group\u2019s activities are considered to be an individual operating segment due to the uniform nature of the Group\u2019s operations within a single geographical area, overseen by the same management and subject to the same regulations. The fair value estimate is categorised as level 3 in the fair value hierarchy. Annual impairment tests were performed at both 31 December 2024 and 31 December 2023. These reviews were carried out on a fair value less cost of disposal basis using risk-adjusted cash flow projections from the approved business plans, including the same commodity prices, life of field cost profiles and production volumes used for impairment of oil and gas assets (see note 19), discounted at a post-tax discount rate of 10.0% (2023: 10.3%). Assumptions and estimates in the Group impairment models are detailed in note 3. The recoverable amount of the North Sea CGU at 31 December 2024 was $418.8 million higher than its carrying amount, including goodwill, and hence no impairment was recorded (2023 : $nil). An increase of 1% in the discount rate assumption would not result in a post-tax impairment of goodwill. Details of further sensitivities are provided in note 19.", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-422": { "value": "
19. Impairment charges on oil and gas assets
2024 2023
$\u2019000 $\u2019000
D&P assets (note 15)
(148,815)
(559,472)
Decommissioning cost estimate changes on assets which have either been fully written off or have ceased production (note 23)
(99,672)
\u2013
Fixed asset additions on assets that have been fully written off (note 15)
(12,251)
\u2013
Other movements
(2,246)
1,536
Total impairment charges on D&P assets
(262,984)
(557,936)
The impairment charge on D&P assets of $148.8 million (2023: $559.5 million) principally reflects a charge for the Greater Stella Area (GSA) of $117 million due to a downward revision of reserves, lower gas prices than previously
forecast and EPL changes together with a charge of $32 million in respect of Pierce due to lower oil prices than previously forecast and EPL changes. The charge in 2023 primarily related to Alba of $141 million and GSA of $373 million.
In addition, decommissioning cost estimate changes on fields which have been fully written off or have ceased production amounted to $99.7 million and fixed asset additions on fields which have been fully written off amounted to
$12.3 million.
Estimated production volumes, supported by third-party analysis, and cash flows used in impairment reviews are considered up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure
and are derived from management approved business plans.
An impairment review was carried out at the end of 2024 on the Group\u2019s producing assets with the main triggers being lower forward oil and gas prices and changes in EPL legislation. The review was carried out on a fair value less
cost of disposal basis using risk adjusted cash flow projections discounted at a post-tax discount rate of 10.0%, and represents level 3 in the fair value hierarchy. The post-tax recoverable amount for GSA and Pierce was $2 million and
$25 million, respectively.
The following assumptions were used at Q4 2024 in developing the cash flow model and applied over the expected life of the respective fields:
Post-tax Price assumptions (nominal)
discount rate
assumption
2025
2026
2027
2028
2029
2030
20311
Oil
10.0%
$75/bbl
$74/bbl
$77/bbl
$79/bbl
$80/bbl
$82/bbl
$83/bbl
Gas
10.0%
98p/therm
84p/therm
81p/therm
82p/therm
83p/therm
85p/therm
87p/therm
1 Post-2031, an annual 2% increase is applied to the price assumptions.
With all other assumptions held constant, a 20% decrease in the forecast revenues, illustrating a 20% decrease in commodity prices, would result in an additional post-tax impairment of PP&E of $303 million (2023: $22 million)
at 31 December 2024. In addition, under this scenario there would be a goodwill impairment of $929 million. This sensitivity is considered to be consistent with those applied to the going concern and viability assessments in that it
assumes that the 10% reduction in production and the 10% increases in operating and capital expenditures are offset by the mitigation strategies within the control of management as described in note 3.
A 20% increase in forecast revenues would reduce the reported post-tax impairment by $24 million (2023: $26 million). An increase or decrease of 1% in the discount rate assumption would not result in a material additional post-tax
impairment or reversal of impairment of PP&E.
The Group has also conducted a sensitivity scenario on the climate-related risk of a reduction in demand for oil and gas commodity prices due to changing consumer preferences and/or government regulations. Utilising the Climate
Scenario average oil price while maintaining all other parameters in line with the base case, would result in an additional post-tax impairment of PP&E of $63 million (2023: nil). To calculate the Climate Scenario average oil and gas
prices, the Group used data from the International Energy Agency (IEA) climate scenarios (NZ, STEPS, APS) price assumptions.
An impairment review was carried out at the end of 2023 on the Group\u2019s producing assets with the main triggers being a reduction in future reserves on Alba, a decrease in short-term forward oil prices against all oil producing CGUs and
a decrease in short-term gas prices for GSA and other predominantly gas-producing CGUs with relatively short remaining useful economic lives. The review was carried out on a fair value less cost of disposal basis using risk adjusted cash
flow projections discounted at a post-tax discount rate of 10.3%, and represents level 3 in the fair value hierarchy. The recoverable amount (post tax) for Alba and GSA was $nil and $29.7 million, respectively.
The following assumptions were used at Q4 2023 in developing the cash flow model and applied over the expected life of the respective fields:
Post-tax Price assumptions (nominal)
discount rate
assumption
2024
2025
2026
2027
2028
2029
2030
1
Oil
10.3%
$85/bbl
$83/bbl
$87/bbl
$90/bbl
$93/bbl
$96/bbl
$99/bbl
Gas
10.3%
101p/therm
96p/therm
83p/therm
85p/therm
87p/therm
89p/therm
90p/therm
1 Post 2030, an annual 2% is applied to the price assumptions.
", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-423": { "value": "
20. Borrowings
2024 2023
$\u2019000 $\u2019000
Current
Accrued interest costs on borrowings
(23,196)
(34,420)
Unamortised short-term bank fees
6,603
3,036
Unamortised short-term senior notes fees
3,568
1,471
Total current borrowings
(13,025)
(29,913)
Non-current
RBL facility
(150,000)
\u2013
Senior unsecured notes
(750,000)
(625,000)
bp unsecured loan
\u2013
(100,000)
Project capital expenditure facility
(150,000)
\u2013
Unamortised long-term bank fees
24,546
4,555
Unamortised long-term senior notes fees
13,531
2,207
Total non-current borrowings
(1,011,923)
(718,238)
Adjusted net debt, which does not include accrued interest on borrowings, lease liabilities or unamortised fees, is set out in non-GAAP measures on pages 249 to 252.
Reserves Based Lending (RBL) facility
During 2024, the Group completed a refinancing of the RBL facility. The refinancing represented an early exit from and extinguishment of the original RBL facility and replacement with a new RBL facility based on market terms at
the date of the refinancing. There was no net cash receipt or payment for the $150 million principal amount of the RBL on refinancing as the drawdown was re-distributed between syndicate banks to the RBL by the facility agent. The
new RBL facility amount at 31 December 2024 was $1.5 billion, consisting of a loan facility of $1,000 million and a letter of credit facility of $500 million, with a maturity to 2029, and subject to interest at a reference rate of SOFR
plus 4.0% in years one to four and SOFR plus 4.25% thereafter. At 31 December 2024, the total loan availability was $1,000 million (2023: $725 million), of which $150 million (2023: none) was drawn down, leaving an amount of
$850 million (2023: $725 million) being available for drawdown. In addition, under the new RBL facility, there is an accordion facility of up to $1,000 million, of which $265 million was committed at 31 December 2024.
Loan fees of $32.4 million relating to the refinancing of the RBL facility were capitalised and are being amortised over the term of the loan. Of this amount, $31.7 million (2023: $nil) was paid in the year to 31 December 2024 and
$0.7 million (2023: $nil) was accrued at 31 December 2024. As at 31 December 2024, $31.1 million (2023: $6.0 million) remains to be amortised. Unamortised fees of $5.3 million were written off to finance costs on the refinancing
which extinguished the previous RBL facility.
The obligations of the borrower under the RBL facility are secured by the assets of the guarantor members of the Group, such as security including share pledges, floating charges and/or debentures. Total assets pledged as security at
31 December 2024 was $8,275 million (2023: $6,324 million).
Covenants under the RBL are detailed below.
Senior notes In 2024, the Group completed the refinancing of its senior unsecured notes with the issuance of $750 million 8.125% senior unsecured notes due October 2029 and repayment in full of the $625 million 9.0% 2026 notes issued during 2021. The refinancing of the senior notes represented an early exit from and extinguishment of the original 2026 senior notes and replacement with new senior notes based on market terms at the date of the refinancing. Loan fees of $17.8 million relating to the new senior notes were capitalised and are being amortised over the life of the loan, $17.1 million (2023: $3.7 million) remains to be amortised as at 31 December 2024.Unamortised fees of $2.6 million relating to the 2026 notes, together with an associated $14.1 million early repayment fee, were written off to finance costs on the refinancing. The Group received a net cash inflow of $86.8 million from the refinancing of the Senior Notes, reflecting Senior Notes 2029 proceeds of $750.0 million less repayment of Senior Notes 2026 of $625.0 million less fees and interest of $38.2 million comprising $14.1 million of early repayment charges and $15.1 million interest on the Senior Notes due 2026 and $9.0 million of fees in relation to the Senior Notes due 2029. Fees of $7.8 million in relation to the new senior notes were paid separately and $1.0 million was accrued at 31 December 2024. bp facility The $100 million facility with bp was repaid in full as part of the refinancing in October 2024. Project capital expenditure facility The project capital expenditure facility of up to $150 million relates to a field development. The full amount of this facility was drawn at 31 December 2024 (2023: $nil) and it is repayable by instalment expected to be from 2027. Under the terms of the arrangement, interest is payable at a rate of SOFR (subject to a minimum of 5%) plus a commercially agreed margin. Covenants The Group is subject to covenants related to the RBL facility. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the facility agreements, potentially resulting in accelerated repayment of the debt obligations. The Group was in compliance with all its relevant quarterly financial and operating covenants during all periods shown for the RBL facility. There are no ongoing maintenance or financial covenant tests associated with the $750 million unsecured notes. In addition to the below financial covenants, the Group is subject to restrictive covenants under the RBL facility and 2029 notes. These restrictive covenants include restrictions on: making certain payments (including,subject to certain exceptions, dividends and other distributions); certain activities with respect to outstanding share capital; repaying or redeeming subordinated debt or share capital; creating or incurring certain liens; making certain acquisitions and investments or loans; selling, leasing or transferring certain assets including shares of any of the Group\u2019s restricted subsidiaries; incurring expenditure on exploration and appraisal activities in excess of approved levels; guaranteeing certain types of the Group\u2019s other indebtedness; expanding into unrelated businesses; merging or consolidating with other entities; or entering into certain transactions with affiliates. The key financial covenant and other conditions in the RBL which, if not met, could trigger repayment within 12 months of the reporting date include: \u2022 As at the end of each 12 month period ending 30 June and 31 December, the ratio of adjusted net debt to adjusted EBITDAX shall be less than 3.5:1. 'Adjusted net debt' referred to is not an IFRS measure. The Group uses adjusted net debt as a measure to assess its financial position. Adjusted net debt comprises amounts outstanding under the Group\u2019s RBL facility, project capital expenditure facility and senior notes, less cash and cash equivalents; and \u2022 On submission of Corporate Cashflow Projections, total projected sources of funds must exceed the total projected uses of funds for the following 12-month period, or if tested prior to first oil from Rosebank, a period of up to 24 months. Corporate Cashflow Projections must be submitted in June and December each year and on the occurrence of certain events (including on refinancing, when an interest in a petroleum asset is acquired or when certain distributions are made). \u2022 The ratio of the net present value of cash flows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1; and \u2022 The ratio of the net present value of cash flows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.
30. Financial instruments
To estimate the fair value of financial instruments, the Group uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilise observable market data. In addition to market
information, the Group incorporates transaction specific details that market participants would utilise in a fair value measurement, including the impact of non-performance risk. The Group characterises inputs used in determining
fair value using a hierarchy that prioritises inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realised or settled in a current
market transaction. The three levels of the fair value hierarchy are as follows:
\u2022 Level 1 \u2013 inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and
volume to provide pricing information on an ongoing basis.
\u2022 Level 2 \u2013 inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market
interest rates and volatility factors, which can be observed or corroborated in the marketplace. The Group obtains information from sources such as the New York Mercantile Exchange and independent price publications.
\u2022 Level 3 \u2013 inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument\u2019s fair value.
In forming estimates, the Group utilises the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorised based upon the
lowest level of input that is significant to the fair value measurement. The valuation of over-the-counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that primarily
rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorised as Level 2.
Gains or losses on financial instruments, that are not hedge accounted for, are recorded through the 'other gains' line in the consolidated statement of profit or loss. Credit valuation adjustments (CVA) and debit valuation adjustments
(DVA) are calculated for each trade using two key inputs, being future exposures and credit spreads (incorporating both probability of default and loss given default). Future exposures have been estimated using an expected exposure-
based approach over the lifetime of the trades. For the risk associated with counterparties, the credit spread is calculated using market observable credit default spreads. For the own credit risk, the credit spread is calculated using
reference to a senior unsecured quoted publicly traded bond of the Group using appropriate tenor adjustments, except for out-of-the-money derivatives with counterparties which are in the Group\u2019s RBL. These derivatives rank higher
than those with other counterparties as they are fully secured as part of the RBL agreement. Therefore, for the own risk credit risk adjustment (DVA) it has been estimated that the loss given default is zero and hence there is no DVA
recognised for those derivatives which are with counterparties of the RBL.
All of the Group\u2019s assets are pledged as security against borrowings.
The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2024 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through profit in hedge Total carrying
amortised cost or loss relationships amount
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Financial assets
Cash and cash equivalents
165,123
\u2013
\u2013
165,123
Other financial assets
11,317
\u2013
\u2013
11,317
Trade and other receivables \u2013 excluding VAT receivable
411,056
\u2013
\u2013
411,056
Derivative financial instruments
\u2013
\u2013
32,962
32,962
Financial liabilities
Borrowings
(1,024,948)
\u2013
\u2013
(1,024,948)
Trade and other payables \u2013 excluding deferred income, inventory overlift and bonus/holiday pay accruals
(439,674)
\u2013
\u2013
(439,674)
Lease liability
(40,159)
\u2013
\u2013
(40,159)
Contingent and deferred consideration
(272,758)
(240,491)
\u2013
(513,249)
Derivative financial instruments
\u2013
(7,484)
(143,979)
(151,463)
(1,549,035)
The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2023 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through profit in hedge Total carrying
amortised cost or loss relationships amount
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Financial assets
Cash and cash equivalents
153,215
\u2013
\u2013
153,215
Trade and other receivables \u2013 excluding VAT receivable
330,351
\u2013
\u2013
330,351
Derivative financial instruments
\u2013
2,782
154,525
157,307
Financial liabilities
Borrowings
(748,151)
\u2013
\u2013
(748,151)
Trade and other payables \u2013 excluding deferred income, inventory overlift and bonus/holiday pay accruals
(343,279)
\u2013
\u2013
(343,279)
Lease liability
(20,559)
\u2013
\u2013
(20,559)
Contingent and deferred consideration
(63,979)
(296,390)
\u2013
(360,369)
Derivative financial instruments
(10,373)
(3,335)
(13,708)
(845,193)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2024:
Level 1 Level 2 Level 3 Total Fair Value
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Contingent consideration (note 26)
\u2013
(1,165)
(239,326)
(240,491)
Derivative financial instrument asset
\u2013
32,962
\u2013
32,962
Derivative financial instrument liability
\u2013
(151,463)
\u2013
(151,463)
Movements in level 3 financial instruments in the 12 months to 31 December 2024 were as follows:
$\u2019000
At 1 January 2024
(272,351)
Cash settlements
14,995
Changes in fair value
18,030
At 31 December 2024
(239,326)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2023:
Level 1 Level 2 Level 3 Total Fair Value
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Contingent consideration (note 26)
\u2013
(24,039)
(272,351)
(296,390)
Derivative financial instrument asset
\u2013
157,307
\u2013
157,307
Derivative financial instrument liability
\u2013
(13,708)
\u2013
(13,708)
Movements in level 3 financial instruments in the 12 months to 31 December 2023 were as follows:
$\u2019000
At 1 January 2023
(223,246)
Additions
(26,872)
Accretion
(8,799)
Changes in fair value
(13,434)
At 31 December 2023
(272,351)
Level 3 contingent consideration is valued on a discounted cash flow basis with the key inputs being commodity prices, the probability of certain future events occurring (\u2018trigger events\u2019) and the discount rate.
The forecast cash flows are discounted at a rate of 6.33% (31 December 2023: 4.6%).
Management has considered alternative scenarios to assess the valuation of the contingent consideration including, but not limited to, the key accounting estimate relating to the oil price. A reduction or increase in the price assumptions
of 20% are considered to be reasonably possible changes. A 20% reduction in the oil price would result in a decrease in contingent consideration of $nil million (31 December 2023: $23.3 million) as the forecast price is already at a level
which is lower than the trigger price. A 20% increase in the oil price would lead to an increase in contingent consideration of $21.7 million (31 December 2023: $41.0 million).
The following table summarises the sensitivity of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date resulting from a 20% change in the probability of a trigger event
occurring, risking of project and conditions being met for payment of contingent consideration, with all other variables held constant. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in probability $\u2019000 $\u2019000
20% decrease in probability
84,245
97,119
20% increase in probability
(77,051)
(84,086)
The following table summarises the sensitivity of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date resulting from a 1% decrease in discount rate, with all other variables
held constant. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in discount rate $\u2019000 $\u2019000
1% decrease in discount rate
(5,707)
(5,284)
A 1% increase in discount rate would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant.
Financial instruments of the Group consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in the financial statements. At 31 December 2024
and 31 December 2023, financial instruments and the carrying amounts reported on the balance sheet approximates the fair values with the exception of borrowings. The carrying amount of borrowing is at amortised cost
of $1,024.9 million (2023: $748.2 million) and the equivalent fair value is $1,025.5 million (2023: $781.4 million) that was categorised as level 3 in the fair value hierarchy level. Equivalent fair value was calculated using
discounted cash flow method. The unobservable input is adjustment due to credit risk to risk free rates.
The table below presents the gain on financial instruments that has been recognised in the consolidated statement of profit or loss as disclosed in note 8.
2024 2023
$\u2019000 $\u2019000
Revaluation of forex forward contracts
(1,310)
7,313
Revaluation of interest rate swaps
(637)
(6,488)
Revaluation of commodity hedges
2,291
42,006
Total revaluation gain on financial instruments
344
42,831
Realised gains/(losses) on forex forward contracts
5,760
(6,282)
Realised gains on interest rate swaps
638
6,967
Realised losses on commodity hedges
(1,575)
(457)
Total gain on financial instruments (note 8)
5,167
43,059
Cash flow hedge reserve
The table below presents the movement in financial instruments that has been recognised through the statement of comprehensive income relating to the cash flow hedge reserve:
2024 2023
Cash flow hedge reserve $\u2019000 $\u2019000
At 1 January
39,818
16,710
Change in fair value of derivative instruments
(68,492)
358,141
Amounts recycled to revenue
(135,122)
(265,711)
Amounts recycled to operating costs
(8,738)
\u2013
Amounts recycled to dividends
(1,285)
\u2013
Amount per consolidated statement of comprehensive income
(213,637)
92,430
Deferred tax on movement in year
158,035
(69,322)
Cash flow hedge reserve at 31 December
(15,784)
39,818
Cost of hedging reserve
The table below presents the movement in financial instruments that has been disclosed through the statement of comprehensive income relating to the cost of hedging reserve:
2024 2023
Cost of hedging reserve $\u2019000 $\u2019000
At 1 January
4,068
3,275
Change in fair value of the intrinsic value of derivative instruments
(55,744)
(12,269)
Amounts recycled to revenue \u2013 oil put premiums
1,697
11,850
Amounts recycled to revenue \u2013 gas put premiums
3,240
3,590
Amount per consolidated statement of comprehensive income
(50,807)
3,170
Deferred tax on movement in year
37,607
(2,378)
Cost of hedging reserve at 31 December
(9,132)
4,068
The Group has identified that it is exposed principally to these areas of market risk.
i) Commodity risk
Commodity price risk related to crude oil prices is the Group\u2019s most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply
and demand fundamentals. The Group is also exposed to natural gas price movements on uncontracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions.
The Group\u2019s expenditures are subject to the effects of inflation and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. The Group may periodically use different types of
derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows.
In all periods presented, the Group has designated certain commodity options as a cash flow hedge of highly probable sales. Because the critical terms (i.e. the quantity, maturity and underlying price) of the commodity option and
their corresponding hedged items are the same, the Group performs a qualitative assessment of effectiveness and it is expected that the intrinsic value of the commodity option and the value of the corresponding hedged items will
systematically change in opposite direction in response to movements in the price of underlying commodity if the price of the commodity increases above the strike price of the derivative. The main source of hedge ineffectiveness in
these hedge relationships is the effect of the counterparty and the Group\u2019s own credit risk on the fair value of the option contracts, which is not reflected in the fair value of the hedged item and if the forecast transaction will happen
earlier or later than originally expected. There was no hedge ineffectiveness in the current or prior year.
The Group\u2019s target is to hedge oil and gas prices up to a maximum of 75% of the next 12 months\u2019 production on a rolling annual basis, up to 50% in the following 12-month period and 25% in the subsequent 12-month period. On a rolling
basis, the Group has minimum and maximum hedging requirements under the RBL. The minimum requirements depend on levels of utilisation with reference to the latest borrowing base amount, as follows:
\u2022 If drawn amounts under the loan tranche of the RBL are below 10%, no hedging is required;
\u2022 If drawn amounts are above 10% but below 50%, the Group is required to hedge no less than 35% for the first 12 months and no less than 20% for the following 12 month period; and
\u2022 If drawn amounts are equal to or greater than 50%, the Group is required to hedge no less than 50% for the first 12 months and no less than 30% for the following 12 month period.
Maximum hedging volumes are set, on a rolling basis, at 85% for year one, 65% for year two, 50% for year three and 30% for year four, and 0% thereafter.
The table below represents total commodity hedges in place at the 2024 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 25 - Dec 25
3,505,500
bbls
$78/bbl
Oil collars
Jan 25 - Dec 25
1,969,500
bbls
$74/bbl floor - $85/bbl ceiling
Gas swaps
Jan 25 - Dec 26
296,750,000
therms
98p/therm
Gas puts
Jan 25 - Dec 26
217,725,000
therms
81p/therm
Gas collars
Jan 25 - Dec 26
348,555,000
therms
83p/therm floor - 102p/therm ceiling
The table below represents total commodity hedges in place at the 2023 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 24 \u2013 Dec 24
1,931,500
bbls
$82/bbl
Oil collars
Jan 24 \u2013 Dec 24
2,744,000
bbls
$75/bbl floor \u2013 $87/bbl ceiling
Gas swaps
Jan 24 \u2013 Dec 24
53,175,000
therms
140p/therm
Gas swaps
Jan 25 \u2013 Sep 25
18,225,000
therms
120p/therm
Gas collars
Jan 24 \u2013 Dec 24
123,350,000
therms
135p/therm floor \u2013 210p/therm ceiling
Gas collars
Jan 25 \u2013 Mar 25
9,000,000
therms
130/therm floor \u2013 185p/therm ceiling
The following table summarises the sensitivity of a 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of commodity derivatives at the reporting date. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in realised commodity price $\u2019000 $\u2019000
20% decrease in realised oil price
(235,713)
(177,151)
20% decrease in realised gas price
(119,799)
(146,794)
A 20% increase in realised commodity prices would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. ii) Interest risk The calculation of interest payments for the RBL facility and the optional project capital expenditure facility incorporate SOFR. The Group is, therefore, exposed to interest rate risk to the extent that SOFR may fluctuate. The Group mitigates the risk of SOFR fluctuations by entering into interest rate swaps on floating rates. There were no interest rate financial instruments in place at either 31 December 2024 or 31 December 2023.
The following table summarises the sensitivity of an increase of 250 basis points in SOFR, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary liabilities at the reporting date.
2024 2023
Change in interest rate $\u2019000 $\u2019000
Increase of 250 basis points
(8,369)
(22,370)
A decrease in 250 basis points in interest rates would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant.
iii) Foreign exchange rate risk
The Group is exposed to foreign exchange risks to the extent it transacts in various currencies, while measuring and reporting its results in US Dollars. Since time passes between the recording of a receivable or payable transaction and its
collection or payment, the Group is exposed to gains or losses on non-US Dollar amounts and on balance sheet translation of monetary accounts denominated in non-US Dollar amounts due to spot rate fluctuations from year-to-year.
As at 31 December 2024, the Group had an average of \u00a321.3 million per quarter hedged at an average forward rate of $1.273:\u00a31 for the period January to December 2025. As at 31 December 2024, the Group had an average
of \u00a349.5 million per quarter hedged at an average collar floor of $1.268:\u00a31 and average collar ceiling of $1.298:\u00a31 for the period January to December 2025.
As at 31 December 2023, the Group had an average of \u00a310.2 million per quarter hedged at an average forward rate of $1.219:\u00a31 for the period January to December 2024. As at 31 December 2023, the Group had an average
of \u00a330.3 million per quarter hedged at an average collar floor of $1.200:\u00a31 and average collar ceiling of $1.230:\u00a31 for the period January to December 2024.
The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying
value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is less significant.
2024 2023
Change in Sterling foreign exchange rate $\u2019000 $\u2019000
10% weakening of Sterling against the US Dollar (2023 revised as explained below)
(6,895)
(6,855)
In the 2023 Annual Report and Accounts, the Group incorrectly included non-monetary items denominated in Sterling to calculate the above sensitivity analysis. The correct impact on profit before tax was a loss of $7 million and not
a loss of $123 million as disclosed previously.
A 10% strengthening of Sterling against the US Dollar would have had the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant.
The Group's Sterling denominated monetary net assets at 31 December 2024 were \u00a355 million (2023: \u00a353.8 million).
iv) Credit risk
The majority of the Group\u2019s trade and other receivables are with customers in the oil and gas industry and are subject to normal industry credit risks and are unsecured. Customers of the Group are mainly oil and gas majors with good
credit ratings and low credit risk, including bp, Eni and Shell.
The Group assesses partners\u2019 creditworthiness before entering into farm-in or joint venture agreements. In the past, the Group has not experienced credit loss in the collection of accounts receivable. As the Group\u2019s exploration,
drilling and development activities expand with existing and new joint venture partners, the Group will assess and continuously update its management of associated credit risk and related procedures.
The Group regularly monitors all customer receivable balances outstanding in excess of 90 days for ECLs. As at 31 December 2024, substantially all accounts receivables are current, being defined as less than 90 days. The Group has
no allowance for doubtful accounts as at 31 December 2024 (31 December 2023: $nil).
The Group may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The Group\u2019s exposure is limited to those counterparties holding derivative
contracts with positive fair values at the reporting date and these counterparties represent a very low risk of default. As at 31 December 2024, the Group\u2019s exposure is $nil (31 December 2023: $nil).
Credit valuation adjustments (CVA) and debit valuation adjustments (DVA) are calculated for each trade using two key inputs, being future exposures and credit spreads (incorporating both probability of default and loss-given default).
Future exposures have been estimated using an expected exposure-based approach over the lifetime of the trades. For the risk associated with counterparties, the credit spread is calculated using market observable credit default
spreads. For the own credit risk, the credit spread is calculated using reference to a senior unsecured quoted publicly traded bond of the Group using appropriate tenor adjustments, except for out-of-the-money derivatives with
counterparties which are in the Group\u2019s RBL. These derivatives rank higher than those with other counterparties as they are fully secured as part of the RBL agreement. Therefore for the own risk credit risk adjustment (DVA) it has
been estimated that the loss given default is zero and hence there is no DVA recognised for those derivatives which are with counterparties of the RBL.
The Group also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values.
v) Liquidity risk
Liquidity risk includes the risk that as a result of its operational liquidity requirements, the Group will not have sufficient funds to settle a transaction on the due date. The Group manages liquidity risk by maintaining adequate
cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Group considers the maturity profiles of its financial assets and liabilities.
As at 31 December 2023 and 2024, substantially all accounts payable are current. As borrowings are linked to SOFR, a spot rate at 31 December 2024 was used to calculate future borrowings cash flows.
The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2024:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(439,674)
\u2013
\u2013
(439,674)
(439,674)
Contingent and deferred consideration
\u2013
(310,132)
(212,908)
(44,536)
(567,576)
(513,249)
Lease liabilities
5.69%
(21,046)
(21,876)
\u2013
(42,922)
(40,159)
Borrowings
8.14%
(85,462)
(1,356,881)
\u2013
(1,442,343)
(1,024,948)
(856,314)
(1,591,665)
(44,536)
(2,492,515)
(2,018,030)
The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2023:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(343,279)
\u2013
\u2013
(343,279)
(343,279)
Contingent and deferred consideration
\u2013
(101,669)
(248,388)
(44,508)
(394,565)
(360,369)
Lease liabilities
6.07%
(20,152)
(669)
\u2013
(20,821)
(20,559)
Borrowings
8.85%
(64,190)
(840,085)
\u2013
(904,275)
(748,151)
(529,290)
(1,089,142)
(44,508)
(1,662,940)
(1,472,358)
The following tables set out the details of the Group\u2019s liquidity analysis for its derivative financial instruments based on contractual maturities. The tables have been drawn up based on the undiscounted net cash inflows and outflows on derivative instruments that settle on a net basis, and the undiscounted gross inflows and outflows on those derivatives that require gross settlement. When the amount payable or receivable is not fixed, the amount disclosed has been determined by reference to the projected interest rates as illustrated by the yield curves existing at the reporting date.
Within Within
1 year 2 to 5 years Total
At 31 December 2024 $\u2019000 $\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(74,252)
(10,293)
(84,545)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(191,464)
\u2013
(191,464)
Foreign exchange collars \u2013 gross outflows
(191,074)
\u2013
(191,074)
(456,790)
(10,293)
(467,083)
Within Within
1 year 2 to 5 years Total
At 31 December 2023 $\u2019000 $\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(2,290)
\u2013
(2,290)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(113,342)
\u2013
(113,342)
Foreign exchange collars \u2013 gross outflows
(155,071)
\u2013
(155,071)
(270,703)
\u2013
(270,703)
vi) Capital management The Group\u2019s objectives when managing capital are to safeguard the Group\u2019s ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required. The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates eroding the Group\u2019s financial results.
31. Derivative financial instruments
The net carrying amount of each category of derivative is set out below:
2024 2023
$\u2019000 $\u2019000
Oil swaps \u2013 cash flow hedge
19,836
9,913
Oil collars \u2013 cash flow hedge
6,536
7,434
Gas swaps \u2013 cash flow hedge
(49,522)
47,232
Gas swaps \u2013 non-cash flow hedge
\u2013
(2,290)
Gas collars \u2013 cash flow hedge
(81,185)
89,944
Interest rate swaps \u2013 non-cash flow hedge
\u2013
637
FX forwards \u2013 cash flow hedge
214
(3,961)
FX forwards \u2013 non-cash flow hedge
(7,484)
\u2013
FX collars \u2013 cash flow hedge
(6,896)
(3,335)
FX collars \u2013 non-cash flow hedge
\u2013
(1,975)
(118,501)
143,599
2024 2023
Maturity analysis of derivative financial instruments $\u2019000 $\u2019000
Non-current assets
\u2013
17,810
Current assets
32,962
139,497
Non-current liabilities
(20,987)
\u2013
Current liabilities
(130,476)
(13,708)
(118,501)
143,599
The fair value of commodity derivatives is estimated using a net present value model (commodity swaps) or an appropriate option valuation model (options and collars). These contracts are valued using observable market pricing
data including volatilities. A 20% reduction in future commodity prices, with all other assumptions held constant, would result in a decrease in the fair value of derivatives of $260 million (2023: $113 million). A 20% increase in future
commodity prices, with all other assumptions held constant, would result in an increase in the intrinsic value of option derivative instruments at 31 December 2024 of $113 million (2023: $88 million).
Derivative financial instruments that are with counterparties included within the RBL are subject to Master Netting Agreements, this includes the majority of the Group\u2019s derivative financial instruments as at 31 December 2024 and 2023.
The terms of the Master Netting Arrangements create a legally enforceable right of offset that comes into effect only on the occurrence of a specified event of default or termination event or other events not expected to happen in the
normal course of business. Although the Group has the ability to net settle certain transactions with certain counterparties where an election has been made, this is not considered to be significant at 31 December 2024. Accordingly,
the Group has not offset any derivatives balances in the statement of financial position in any of the periods presented.
Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2024 are detailed below:
Amount recognised in the Related amounts not set off in the
statement of financial position statement of financial position Net amount
$000 $000 $000
Derivative assets
32,962
(22,962)
10,000
Derivative liabilities
(151,463)
22,962
(128,501)
Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2023 are detailed below:
Amount recognised in the Related amounts not set off in the
statement of financial position statement of financial position Net amount
$000 $000 $000
Derivative assets
157,306
(4,436)
152,870
Derivative liabilities
(13,708)
4,436
(9,272)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-460": { "value": "20. Borrowings
2024 2023
$\u2019000 $\u2019000
Current
Accrued interest costs on borrowings
(23,196)
(34,420)
Unamortised short-term bank fees
6,603
3,036
Unamortised short-term senior notes fees
3,568
1,471
Total current borrowings
(13,025)
(29,913)
Non-current
RBL facility
(150,000)
\u2013
Senior unsecured notes
(750,000)
(625,000)
bp unsecured loan
\u2013
(100,000)
Project capital expenditure facility
(150,000)
\u2013
Unamortised long-term bank fees
24,546
4,555
Unamortised long-term senior notes fees
13,531
2,207
Total non-current borrowings
(1,011,923)
(718,238)
Adjusted net debt, which does not include accrued interest on borrowings, lease liabilities or unamortised fees, is set out in non-GAAP measures on pages 249 to 252. Reserves Based Lending (RBL) facility During 2024, the Group completed a refinancing of the RBL facility. The refinancing represented an early exit from and extinguishment of the original RBL facility and replacement with a new RBL facility based on market terms at the date of the refinancing. There was no net cash receipt or payment for the $150 million principal amount of the RBL on refinancing as the drawdown was re-distributed between syndicate banks to the RBL by the facility agent. The new RBL facility amount at 31 December 2024 was $1.5 billion, consisting of a loan facility of $1,000 million and a letter of credit facility of $500 million, with a maturity to 2029, and subject to interest at a reference rate of SOFR plus 4.0% in years one to four and SOFR plus 4.25% thereafter. At 31 December 2024, the total loan availability was $1,000 million (2023: $725 million), of which $150 million (2023: none) was drawn down, leaving an amount of $850 million (2023: $725 million) being available for drawdown. In addition, under the new RBL facility, there is an accordion facility of up to $1,000 million, of which $265 million was committed at 31 December 2024. Loan fees of $32.4 million relating to the refinancing of the RBL facility were capitalised and are being amortised over the term of the loan. Of this amount, $31.7 million (2023: $nil) was paid in the year to 31 December 2024 and $0.7 million (2023: $nil) was accrued at 31 December 2024. As at 31 December 2024, $31.1 million (2023: $6.0 million) remains to be amortised. Unamortised fees of $5.3 million were written off to finance costs on the refinancing which extinguished the previous RBL facility. The obligations of the borrower under the RBL facility are secured by the assets of the guarantor members of the Group, such as security including share pledges, floating charges and/or debentures. Total assets pledged as security at 31 December 2024 was $8,275 million (2023: $6,324 million). Covenants under the RBL are detailed below.
Senior notes
In 2024, the Group completed the refinancing of its senior unsecured notes with the issuance of $750 million 8.125% senior unsecured notes due October 2029 and repayment in full of the $625 million 9.0% 2026 notes issued during
2021. The refinancing of the senior notes represented an early exit from and extinguishment of the original 2026 senior notes and replacement with new senior notes based on market terms at the date of the refinancing. Loan fees
of $17.8 million relating to the new senior notes were capitalised and are being amortised over the life of the loan, $17.1 million (2023: $3.7 million) remains to be amortised as at 31 December 2024.Unamortised fees of $2.6 million
relating to the 2026 notes, together with an associated $14.1 million early repayment fee, were written off to finance costs on the refinancing.
The Group received a net cash inflow of $86.8 million from the refinancing of the Senior Notes, reflecting Senior Notes 2029 proceeds of $750.0 million less repayment of Senior Notes 2026 of $625.0 million less fees and interest
of $38.2 million comprising $14.1 million of early repayment charges and $15.1 million interest on the Senior Notes due 2026 and $9.0 million of fees in relation to the Senior Notes due 2029. Fees of $7.8 million in relation to the new
senior notes were paid separately and $1.0 million was accrued at 31 December 2024.
bp facility
The $100 million facility with bp was repaid in full as part of the refinancing in October 2024.
Project capital expenditure facility
The project capital expenditure facility of up to $150 million relates to a field development. The full amount of this facility was drawn at 31 December 2024 (2023: $nil) and it is repayable by instalment expected to be from 2027.
Under the terms of the arrangement, interest is payable at a rate of SOFR (subject to a minimum of 5%) plus a commercially agreed margin.
Covenants
The Group is subject to covenants related to the RBL facility. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the facility agreements, potentially resulting in accelerated
repayment of the debt obligations. The Group was in compliance with all its relevant quarterly financial and operating covenants during all periods shown for the RBL facility. There are no ongoing maintenance or financial covenant tests
associated with the $750 million unsecured notes.
In addition to the below financial covenants, the Group is subject to restrictive covenants under the RBL facility and 2029 notes. These restrictive covenants include restrictions on: making certain payments (including,subject to
certain exceptions, dividends and other distributions); certain activities with respect to outstanding share capital; repaying or redeeming subordinated debt or share capital; creating or incurring certain liens; making certain acquisitions
and investments or loans; selling, leasing or transferring certain assets including shares of any of the Group\u2019s restricted subsidiaries; incurring expenditure on exploration and appraisal activities in excess of approved levels; guaranteeing
certain types of the Group\u2019s other indebtedness; expanding into unrelated businesses; merging or consolidating with other entities; or entering into certain transactions with affiliates.
The key financial covenant and other conditions in the RBL which, if not met, could trigger repayment within 12 months of the reporting date include:
\u2022 As at the end of each 12 month period ending 30 June and 31 December, the ratio of adjusted net debt to adjusted EBITDAX shall be less than 3.5:1. 'Adjusted net debt' referred to is not an IFRS measure. The Group uses adjusted
net debt as a measure to assess its financial position. Adjusted net debt comprises amounts outstanding under the Group\u2019s RBL facility, project capital expenditure facility and senior notes, less cash and cash equivalents; and
\u2022 On submission of Corporate Cashflow Projections, total projected sources of funds must exceed the total projected uses of funds for the following 12-month period, or if tested prior to first oil from Rosebank, a period of up to
24 months. Corporate Cashflow Projections must be submitted in June and December each year and on the occurrence of certain events (including on refinancing, when an interest in a petroleum asset is acquired or when certain
distributions are made).
\u2022 The ratio of the net present value of cash flows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1; and
\u2022 The ratio of the net present value of cash flows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.
", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-424": { "value": "
21. Changes in liabilities arising from financing activities
Non-cash changes
Financing cash Business Fair value Other
1 January 2024
flows
(i)
Additions
(iii)
combinations movements Amortisation
movements
(ii)
31 December 2024
$\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Borrowings (note 20)
748,150
11,955
150,000
\u2013
\u2013
13,226
101,617
1,024,948
Lease liabilities
20,559
(29,378)
25,422
22,049
\u2013
\u2013
1,507
40,159
Interest rate derivatives (note 30)
(637)
637
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
Total liabilities from financing activities
768,072
(16,786)
175,422
22,049
\u2013
13,226
103,124
1,065,107
Non-cash changes
Financing cash Business Fair value Other
1 January 2023
flows
(i)
Additions combinations movements Amortisation
movements
(ii)
31 December 2023
$\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Borrowings (note 20)
1,213,731
(596,642)
\u2013
\u2013
\u2013
4,507
126,554
748,150
Lease liabilities
58,858
(45,085)
3,603
\u2013
\u2013
\u2013
3,183
20,559
Interest rate derivatives (note 30)
(7,125)
6,967
\u2013
\u2013
(479)
\u2013
\u2013
(637)
Total liabilities from financing activities
1,265,464
(634,760)
3,603
\u2013
(479)
4,507
129,737
768,072
(i) The cash flows from borrowings, lease liabilities and interest rate derivatives make up the net amount of proceeds from borrowings and repayments of borrowings in the cash flow statement.
(ii) Other movements include interest accruals and new liabilities in the year.
(iii) Additions to borrowings in 2024 reflects the project capital expenditure facility (see note 20 for further details).
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-461": { "value": "21. Changes in liabilities arising from financing activities
Non-cash changes
Financing cash Business Fair value Other
1 January 2024
flows
(i)
Additions
(iii)
combinations movements Amortisation
movements
(ii)
31 December 2024
$\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Borrowings (note 20)
748,150
11,955
150,000
\u2013
\u2013
13,226
101,617
1,024,948
Lease liabilities
20,559
(29,378)
25,422
22,049
\u2013
\u2013
1,507
40,159
Interest rate derivatives (note 30)
(637)
637
\u2013
\u2013
\u2013
\u2013
\u2013
\u2013
Total liabilities from financing activities
768,072
(16,786)
175,422
22,049
\u2013
13,226
103,124
1,065,107
Non-cash changes
Financing cash Business Fair value Other
1 January 2023
flows
(i)
Additions combinations movements Amortisation
movements
(ii)
31 December 2023
$\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Borrowings (note 20)
1,213,731
(596,642)
\u2013
\u2013
\u2013
4,507
126,554
748,150
Lease liabilities
58,858
(45,085)
3,603
\u2013
\u2013
\u2013
3,183
20,559
Interest rate derivatives (note 30)
(7,125)
6,967
\u2013
\u2013
(479)
\u2013
\u2013
(637)
Total liabilities from financing activities
1,265,464
(634,760)
3,603
\u2013
(479)
4,507
129,737
768,072
(i) The cash flows from borrowings, lease liabilities and interest rate derivatives make up the net amount of proceeds from borrowings and repayments of borrowings in the cash flow statement. (ii) Other movements include interest accruals and new liabilities in the year. (iii) Additions to borrowings in 2024 reflects the project capital expenditure facility (see note 20 for further details).", "dimensions": { "concept": "ifrs-full:DisclosureOfReconciliationOfLiabilitiesArisingFromFinancingActivitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-425": { "value": "22. Trade and other payables
2024 2023
$\u2019000 $\u2019000
Trade payables
(21,910)
(34,559)
Hydrocarbon amounts owed to joint operations/overlift
(102,061)
(72,486)
Other payables
(38,069)
(68,034)
Accruals
(394,602)
(254,781)
Deferred income
(9,829)
(48,747)
(566,471)
(478,607)
The Directors consider the carrying values of trade and other payables to approximate the fair value. Other payables mainly comprise amounts owed due to production adjustments and amounts owed to joint operations partners. Deferred income represents receipts in advance of deliveries to customers. The prior year deferred income was recognised in revenue in the current year", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-462": { "value": "
2024 2023
$\u2019000 $\u2019000
Trade payables
(21,910)
(34,559)
Hydrocarbon amounts owed to joint operations/overlift
(102,061)
(72,486)
Other payables
(38,069)
(68,034)
Accruals
(394,602)
(254,781)
Deferred income
(9,829)
(48,747)
(566,471)
(478,607)
", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-482": { "value": "
2024 2023
$\u2019000 $\u2019000
Trade payables
(21,910)
(34,559)
Hydrocarbon amounts owed to joint operations/overlift
(102,061)
(72,486)
Other payables
(38,069)
(68,034)
Accruals
(394,602)
(254,781)
Deferred income
(9,829)
(48,747)
(566,471)
(478,607)
", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredIncomeExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-426": { "value": "
23. Decommissioning liabilities
2024 2023
$\u2019000 $\u2019000
Balance at 1 January
(1,859,678)
(1,720,540)
Business combination additions (note 17)
(650,999)
\u2013
Accretion
(93,436)
(74,621)
Additions and revisions to estimates
(145,066)
(160,069)
Decommissioning provision utilised
94,098
95,552
Balance at 31 December
(2,655,081)
(1,859,678)
Current
Balance at 1 January
(107,026)
(146,829)
Balance at 31 December
(152,709)
(107,026)
Non-current
Balance at 1 January
(1,752,652)
(1,573,711)
Balance at 31 December
(2,502,372)
(1,752,652)
The total future decommissioning liability represents the estimated cost to decommission, in situ or by removal, the Group\u2019s net ownership interest in all wells, infrastructure and facilities, based upon forecast timing in future periods.
Whereas previously the Group used a uniform nominal discount rate over all future years, it has now revised its methodology to use a short-to-medium-term nominal discount rate and a long-term nominal discount rate. The Group
uses a nominal discount rate of 4.38% for the first five years and 4.86% thereafter (31 December 2023: 4.60% for all years) and an inflation rate of 2.0% (31 December 2023: 2.0%) over the varying lives of the assets to calculate the
present value of the decommissioning liabilities. The impact of a change in discount rate is considered in note 3. Revisions to estimates in the years ended 31 December 2024 and 2023 were due to changes in both cost estimates and
discount rate assumptions.
The estimated 2025 decommissioning spend of $153 million (2023: estimated 2024 decommissioning spend of $107 million) has been treated as a current liability as at 31 December 2024. Although the Group currently expects to
incur decommissioning costs over the next 40 years, it is estimated that approximately 40% of the decommissioning liability relates to assets which are expected to cease production in the next five years and includes spend for assets
that will be reimbursed (see note 11 for further details).
The principal assets where decommissioning activity was ongoing at 31 December 2024 were Alba, Anglia, Causeway, CMS 111, Elgin Franklin, Heather, Hunter, Juliet, Stathspey and Topaz.
", "dimensions": { "concept": "ithacaenergyplc:DisclosureOfDecommissioningLiabilities", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-427": { "value": "
24. Other provisions
2024 2023
$\u2019000 $\u2019000
At 1 January
\u2013
\u2013
Business combination additions (note 17)
(34,865)
\u2013
Cost of gas sales during the year
(1,325)
\u2013
At 31 December
(36,190)
\u2013
Other provisions reflect principally estimated liabilities taken on through the Business Combination in respect of certain historic gas sales agreements along with the ongoing cost of such gas sales agreements. It is not anticipated that
any part of this liability will be settled within 12 months of the balance sheet date and, therefore, it has been classified in its entirety as a non-current liability. The Group expects to start settling these liabilities between one and five years.
", "dimensions": { "concept": "ifrs-full:DisclosureOfProvisionsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-463": { "value": "24. Other provisions
2024 2023
$\u2019000 $\u2019000
At 1 January
\u2013
\u2013
Business combination additions (note 17)
(34,865)
\u2013
Cost of gas sales during the year
(1,325)
\u2013
At 31 December
(36,190)
\u2013
Other provisions reflect principally estimated liabilities taken on through the Business Combination in respect of certain historic gas sales agreements along with the ongoing cost of such gas sales agreements. It is not anticipated that any part of this liability will be settled within 12 months of the balance sheet date and, therefore, it has been classified in its entirety as a non-current liability. The Group expects to start settling these liabilities between one and five years.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherProvisionsContingentLiabilitiesAndContingentAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-428": { "value": "
25. Lease liabilities
2024 2023
Current $\u2019000 $\u2019000
Lease liabilities
(19,447)
(19,898)
2024 2023
Non-current $\u2019000 $\u2019000
Lease liabilities
(20,712)
(660)
The following table sets out a maturity analysis of lease payments, showing the undiscounted lease payments to be paid after the reporting date. All lease liabilities are fully payable within five years from 31 December 2024.
2024 2023
$\u2019000 $\u2019000
Less than one year
(21,046)
(20,152)
One to five years
(21,876)
(669)
Total undiscounted lease payments
(42,922)
(20,821)
Future finance charges
2,763
263
Lease liabilities in the financial statements
(40,159)
(20,558)
2024 2023
$\u2019000 $\u2019000
At 1 January
(20,558)
(58,858)
Additions
(25,422)
(3,603)
Business combination additions (note 17)
(22,049)
\u2013
Interest
(1,508)
(3,183)
Payments
29,378
45,086
At 31 December
(40,159)
(20,558)
Current
(19,447)
(19,898)
Non-current
(20,712)
(660)
(40,159)
(20,558)
The additions in the year to 31 December 2024 relate to the Skandi Gamma supply vessel.
The additions in the year to 31 December 2023 relate to modifications of the Captain Emergency Response and Rescue Vessel (ERRV) lease.
The leased assets added through the Business Combination comprised principally office accommodation, an ERRV lease and a helicopter lease for Cygnus.
Amounts recognised in profit and loss related to leases are detailed in notes 6 and 9.
", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-429": { "value": "
26. Contingent and deferred consideration
2024 2023
Current $\u2019000 $\u2019000
Contingent consideration
(74,990)
(101,669)
Deferred consideration payable to related party for business combination (note 17)
(160,203)
\u2013
Marubeni deferred consideration
(68,293)
\u2013
(303,486)
(101,669)
2024 2023
Non-current $\u2019000 $\u2019000
Contingent consideration
(165,501)
(194,721)
Deferred consideration payable to related party for business combination (note 17)
(44,262)
\u2013
Marubeni deferred consideration
\u2013
(63,979)
(209,763)
(258,700)
2024 2023
$\u2019000 $\u2019000
Cash flows relating to contingent and deferred considerations
(22,994)
(13,567)
Movement in contingent consideration is as follows:
2024 2023
$\u2019000 $\u2019000
At 1 January
(296,390)
(258,896)
Additions
\u2013
(26,872)
Payments made
22,994
7,200
Changes in fair value
32,905
(17,822)
At 31 December
(240,491)
(296,390)
Movement in deferred consideration is as follows:
2024 2023
$\u2019000 $\u2019000
At 1 January
(63,979)
(67,904)
Additions
(204,465)
\u2013
Payments made
\u2013
6,367
Accretion
(4,314)
(2,442)
At 31 December
(272,758)
(63,979)
Cash outflows in the year ended 31 December 2024 of $23.0 million (2023: $13.6 million) are in relation to the consideration payable on the MOGL, Siccar oil price triggers and an interim payment on Rosebank in the year to
31 December 2024.
Marubeni
The contingent consideration arrangement relating to the 2022 acquisition of MOGL depends on whether various milestones in the Sale and Purchase Agreement (SPA) are met as follows: set gross export production volume
from Montrose Infill Project Phase 1, set cumulative gross export production volume following Arbroath well reinstatements, set gross export production volume from next new well in the Shaw Field and, an amount payable during
the Value Sharing Period (1 January 2022 to 31 December 2024) in relation to sales in excess of a set oil trigger price. The amount payable in relation to sales in excess of a set oil trigger price is capped under the terms of the SPA.
The carrying amount at 31 December 2024, discounted at 6.33%, was $78 million (2023: $111 million using a discount rate of 4.6%). The total undiscounted potential consideration as at 31 December 2024 is $228 million
(2023: $230 million).
The Marubeni deferred consideration of $68.3 million is payable 1 July 2025.
Siccar
During the year ended 31 December 2022, the Group acquired Siccar Point Energy, which included elements of consideration that are payable depending on whether various milestones of the SPA are met as follows: Final Investment
Decision and the associated reserves in respect of the Cambo and Rosebank fields and, an amount paid in relation to sales in excess of a set floor oil price. The amount payable in relation to sales in excess of a set oil trigger price is capped
under the terms of the SPA. The carrying amount at 31 December 2024, discounted at 6.33% was $118 million (2023: $130 million using a discount rate of 4.6%). The total undiscounted potential consideration as at 31 December
2024 is $343 million (2023: $362 million).
Others
During the year ended 31 December 2023, the Group acquired a further 30% equity in the Cambo field from Shell. The acquisition included elements of consideration that are payable upon certain events occurring and contingent
consideration has been recognised to reflect this. The consideration value equates to $1.50 per barrel of oil equivalent of the P50 resource volumes of the field, and is payable on the earlier of receipt of proceeds of any subsequent sale
of a working interest in Cambo by the Group, or first oil. The carrying amount at 31 December 2024, discounted at 6.33%, was $11.7 million (2023: $12.7 million undiscounted).
During the year ended 31 December 2023, the Group acquired 40% equity in the Fotla field from Spirit. The acquisition included elements of consideration that are payable upon certain events occurring and contingent consideration
has been recognised to reflect this. The consideration comprises two capped amounts with approximately two-thirds payable on final investment decision and one-third on first production. The carrying amount at 31 December 2024,
discounted at 6.33%, was $9.0 million (2023: $14.2 million undiscounted).
A further $nil (2023: $3.0 million) relates to Yeoman/Marigold which has been fully risked. The unrisked amount is $11.0 million (2023: $11.0 million) which is contingent on achieving Field Development Plan along with a further
$6.0 million (2023: $6.0 million) unrisked on certain production criteria being met.
During the year ended 31 December 2024, the contingent consideration liability in relation to Strathspey, in accordance with the Sale and Purchase Agreement with Chevron, has reduced by $1.9 million to $23.7 million as a result
of changes in variables in the calculation of the liability.
Revaluation of contingent consideration in the year to 31 December 2024 resulted in a decrease of $32.9 million (2023: increase of $17.8 million).
", "dimensions": { "concept": "ithacaenergyplc:DisclosureOfContingentAndDeferredConsideration", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-430": { "value": "
27. Share capital and reserves
(a) Issued share capital
The issued share capital is as follows:
Number of Amount
common shares $\u2019000
At 31 December 2023
1,014,372,281
11,540
Shares issued during the year
639,360,174
8,489
At 31 December 2024
1,653,732,455
20,029
On 3 October 2024, 639,360,174 ordinary shares of \u00a30.01 each were issued to Eni UK Limited, an indirect wholly-owned subsidiary of Eni S.p.A., as consideration for the Eni UK business combination (see note 17 for further details).
On 5 October 2023, 7,807,305 ordinary shares of \u00a30.01 each were issued to the Ithaca Energy plc Employee Benefit Trust (EBT) to satisfy the exercise of share options during the year and in future years.
(b) Share premium
2024 2023
$\u2019000 $\u2019000
At 1 January
308,845
293,712
Additions
852,770
15,133
At 31 December
1,161,615
308,845
The share premium account represents the cumulative difference between the market share price and the nominal share value on the issuance of new ordinary shares multiplied by the number of shares issued.
Additions during 2024 represent the difference between the nominal value per share of \u00a30.01 and the opening share price on the day of the completion of the Eni business combination multiplied by the number of shares issued.
Additions during 2023 represent the difference between the nominal value per share of \u00a30.01 and the closing share price on the day before the shares were issued to the EBT multiplied by the number of shares issued.
(c) Capital contribution reserve
2024 2023
$\u2019000 $\u2019000
At 1 January and 31 December
181,945
181,945
(d) Own shares
2024 2023
$\u2019000 $\u2019000
At 31 December
(9,592)
(12,412)
Own shares comprise shares held in the Ithaca Energy plc EBT, which are being used to satisfy the exercise of employee share options. During the year to 31 December 2024, 1,860,112 (2023: 1,443,561) ordinary shares were used to
satisfy the exercise of share options. At 31 December 2024, the EBT held 6,325,918 (2023: 8,186,030) ordinary shares of \u00a30.01 each.
(e) Share-based payment reserve (note 33)
2024 2023
$\u2019000 $\u2019000
At 31 December
18,788
15,494
The share-based payment reserve represents the cumulative charge for share options, as described in note 33, less the cumulative cost of share option exercises.
", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-464": { "value": "(a) Issued share capital The issued share capital is as follows:
Number of Amount
common shares $\u2019000
At 31 December 2023
1,014,372,281
11,540
Shares issued during the year
639,360,174
8,489
At 31 December 2024
1,653,732,455
20,029
On 3 October 2024, 639,360,174 ordinary shares of \u00a30.01 each were issued to Eni UK Limited, an indirect wholly-owned subsidiary of Eni S.p.A., as consideration for the Eni UK business combination (see note 17 for further details). On 5 October 2023, 7,807,305 ordinary shares of \u00a30.01 each were issued to the Ithaca Energy plc Employee Benefit Trust (EBT) to satisfy the exercise of share options during the year and in future years. ", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-465": { "value": "(b) Share premium
2024 2023
$\u2019000 $\u2019000
At 1 January
308,845
293,712
Additions
852,770
15,133
At 31 December
1,161,615
308,845
The share premium account represents the cumulative difference between the market share price and the nominal share value on the issuance of new ordinary shares multiplied by the number of shares issued. Additions during 2024 represent the difference between the nominal value per share of \u00a30.01 and the opening share price on the day of the completion of the Eni business combination multiplied by the number of shares issued. Additions during 2023 represent the difference between the nominal value per share of \u00a30.01 and the closing share price on the day before the shares were issued to the EBT multiplied by the number of shares issued. (c) Capital contribution reserve
2024 2023
$\u2019000 $\u2019000
At 1 January and 31 December
181,945
181,945
", "dimensions": { "concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-466": { "value": "(d) Own shares
2024 2023
$\u2019000 $\u2019000
At 31 December
(9,592)
(12,412)
Own shares comprise shares held in the Ithaca Energy plc EBT, which are being used to satisfy the exercise of employee share options. During the year to 31 December 2024, 1,860,112 (2023: 1,443,561) ordinary shares were used to satisfy the exercise of share options. At 31 December 2024, the EBT held 6,325,918 (2023: 8,186,030) ordinary shares of \u00a30.01 each. ", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-431": { "value": "
28. Taxation
2023
2024
Restated
1
$\u2019000 $\u2019000
Current tax
Current corporation tax charge
(17,746)
(39,308)
Current EPL tax charge
(221,420)
(333,425)
True-up in respect of prior years
30,573
(17,426)
Total current tax charge
(208,593)
(390,159)
Deferred tax
True-up in respect of prior years
(21,068)
6,370
Group tax (charge)/credit in consolidated statement of profit or loss
(1,905)
304,279
Group tax credit/(charge) in consolidated statement of other comprehensive income
195,642
(71,700)
Total deferred tax credit
172,669
238,949
Deferred Petroleum Revenue Tax
Deferred PRT credit in statement of profit or loss
50,381
70,037
Total tax charge through consolidated statement of profit or loss
(181,186)
(9,473)
1 See note 2.
The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:
2023
2024
Restated
1
$\u2019000 $\u2019000
Accounting profit before tax
334,339
302,027
At tax rate of 40% (2023: 40%)
(133,735)
(120,811)
Non-deductible expense
8,700
(34,578)
Financing costs not allowed for SCT
(13,581)
(704)
Ring Fence Expenditure Supplement
14,340
102,866
Deferred tax effect of investment allowance
33,219
56,930
True-up in respect of prior years
9,504
(11,673)
Deferred PRT net of corporation tax
30,229
42,022
Deferred tax on EPL
119,102
292,829
Current tax on EPL
(221,420)
(333,425)
Income taxed at different rates
(27,956)
\u2013
Share-based payments
412
1,945
Unrecognised tax losses
\u2013
(4,874)
Total tax charge recorded in the consolidated statement of profit or loss
(181,186)
(9,473)
1 See note 2.
The Company is UK tax resident. The effective rate of tax applicable for UK ring fence oil and gas activities in both 2024 and 2023 was 40% (excluding the Energy Profits Levy), consisting of a Ring Fence Corporation Tax rate of 30% and
the supplementary charge of 10%. Items affecting the tax charge include interest income taxed at non-oil and gas tax rate of 25%, true-ups in respect of prior years resulting from filing of prior year tax returns, a 10% uplift on ring fence
losses, Ring Fence Expenditure Supplement increasing the losses available to offset future profits subject to Ring Fence Corporation Tax and Supplementary Charge. In addition, investment allowance, a 62.5% uplift on capital expenditure,
is available reducing the profits subject to the supplementary charge only. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK, however, adjustments to recognised deferred PRT assets are made to reflect
updated expectations of reversal against profits subject to the 0% PRT rate. The Energy Profits Levy was enacted on 14 July 2022 with further changes announced on 17 November 2022 such that the Levy was increased to 35% from
1 January 2023 until 31 March 2028 increasing the effective UK ring fence oil and gas tax rate to 75%. On 6 March 2024, it was announced that EPL will be extended by one year to 31 March 2029 and on 29 July 2024, it was announced
that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024. The impact of this was a charge to the consolidated statement of profit or loss of $58.1 million (2023: $nil)
in the year to 31 December 2024. The extensions to 31 March 2029 and 31 March 2030 had not been substantively enacted at 31 December 2024 and are, therefore, not reflected in the results for the year ended 31 December 2024.
Deferred tax at 31 December relates to the following:
2023
2024
Restated
1
$\u2019000 $\u2019000
Deferred corporation tax liability
(2,197,590)
(1,868,022)
Deferred corporation tax asset
3,279,585
2,480,921
Deferred PRT asset
142,141
91,758
Net deferred tax asset
1,224,136
704,657
Deferred tax assets primarily relate to decommissioning liabilities, brought forward tax losses and accumulated losses and profits related to derivative contracts. Deferred tax liabilities primarily relate to accelerated capital allowances on property, plant and equipment and accumulated losses and profits related to derivative contracts. Deferred tax balances are presented net as they arise in the same jurisdiction and the Group has a legally-enforceable right to offset as well as an intention to settle on a net basis. There are unrecognised allowances of up to circa $150 million that have no expiry date and could be recognised in future periods if future revenue from oil and gas activities increases and/ or further actions are undertaken. Non-oil and gas losses of $217 million (2023: $251 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses. The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:
2023
2024
Restated
1
$\u2019000 $\u2019000
At 1 January
704,657
392,457
Profit or loss credit
27,408
380,686
Other comprehensive income credit/(charge)
195,643
(71,700)
Deferred tax on decommissioning reimbursements (note 11)
(916)
3,214
Business combinations (note 17)
297,344
\u2013
At 31 December
1,224,136
704,657
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income, excluding PRT, relates to the following:
2023
2024
Restated
1
$\u2019000 $\u2019000
Accelerated capital allowances
100,974
515,277
Tax losses
(203,307)
(216,937)
Decommissioning provision
61,685
52,440
Deferred PRT
(20,153)
(28,015)
Hedging
2
201,534
(101,744)
Share schemes
963
3,978
Investment allowances
30,973
13,950
172,669
238,949
1 See note 2. 2 Hedging relates to deferred tax on derivatives designated in cash flow hedges and used for economic hedges
Deferred
corporation tax on Accelerated tax
Hedges deferred PRT depreciation Total
Gross deferred corporation tax liabilities $\u2019000 $\u2019000 $\u2019000 $\u2019000
At 1 January 2023
\u2013
(8,688)
(2,250,125)
(2,258,813)
Reclassification from deferred corporation tax assets
(8,678)
\u2013
\u2013
(8,678)
True-up in respect of prior years
2,721
\u2013
8,307
11,028
Origination and reversal of temporary differences
(101,744)
(28,015)
441,281
311,522
At 31 December 2023 as previously stated
(107,701)
(36,703)
(1,800,537)
(1,944,941)
Prior period adjustment (note 2)
\u2013
\u2013
76,919
76,919
At 31 December 2023 and 1 January 2024 as restated
(107,701)
(36,703)
(1,723,618)
(1,868,022)
Business combinations (note 17)
\u2013
\u2013
(549,062)
(549,062)
True-up in respect of prior years
\u2013
\u2013
(16,027)
(16,027)
Origination and reversal of temporary differences
201,534
(20,153)
147,973
329,354
Reclassification to deferred corporation tax assets
(93,833)
\u2013
\u2013
(93,833)
At 31 December 2024
\u2013
(56,856)
(2,140,734)
(2,197,590)
Decommissioning
Share schemes provision Other provisions Tax losses Hedges Total
Gross deferred corporation tax assets $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
At 1 January 2023
\u2013
666,052
\u2013
1,972,174
(8,678)
2,629,548
True-up in respect of prior years
177
\u2013
\u2013
(4,989)
\u2013
(4,812)
Reclassification to deferred corporation tax liabilities
\u2013
\u2013
\u2013
\u2013
8,678
8,678
Origination and reversal of temporary differences
3,802
55,654
\u2013
(211,949)
\u2013
(152,493)
At 31 December 2023 and 1 January 2024
3,979
721,706
\u2013
1,755,236
\u2013
2,480,921
Business combinations (note 17)
\u2013
257,392
21,350
567,666
\u2013
846,408
True-up in respect of prior years
\u2013
(8)
\u2013
(5,033)
\u2013
(5,041)
Origination and reversal of temporary differences
962
60,776
\u2013
(198,274)
\u2013
(136,536)
Reclassification from deferred corporation tax liabilities
\u2013
\u2013
\u2013
\u2013
93,833
93,833
At 31 December 2024
4,941
1,039,866
21,350
2,119,595
93,833
3,279,585
Total
Deferred PRT asset $\u2019000
At 1 January 2023
21,721
Origination and reversal of temporary differences
70,037
At 31 December 2023 and 1 January 2024
91,758
Origination and reversal of temporary differences
50,381
At 31 December 2024
142,141
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2024 of $1,082 million and $142 million, respectively (2023: $613 million and $92 million, respectively) are supported by estimates of the Group\u2019s future taxable income, based on the same price and cost assumptions as used for impairment testing. The Group has undertaken and will undertake further restructuring exercises to move certain assets between Group entities. Existing restructuring exercises have now been substantially completed. The recoverability of the deferred corporation tax asset is supported by this restructuring. The DTA relating to losses within the Group are expected to unwind against taxable profits before the end of 2029. An EPL (or \u2018Levy\u2019) was enacted on 14 July 2022, applying a Levy of 25% to the profits of oil and gas companies until 31 December 2025 or earlier if prices return to normalised levels. On 17 November 2022, the Levy was increased to 35% and extended to 31 March 2028 regardless of oil and gas prices. The Levy is charged on oil and gas profits calculated on the same basis as Ring Fence Corporation Tax (RFCT), however, excludes relief for decommissioning and finance costs. RFCT losses and investment allowance are not available to offset the EPL. On 9 June 2023 an Energy Security Investment Mechanism price floor was announced which would remove the EPL if both average oil and gas prices fall to, or below, $71.40 per barrel for oil and \u00a30.54 per therm for gas, for two consecutive quarters. It is not currently forecast that this price floor will be met for both oil and gas prices and, therefore, there is currently no impact from this on tax carrying values. On 6 March 2024, an extension of the Levy until 31 March 2029 was announced and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024, of which only the rate increase had been enacted at 31 December 2024. Had the two-year extension to 31 March 2030 been enacted at 31 December 2024, this would have reduced the net deferred tax asset by $318 million. This extension was substantively enacted on 3 March 2025 and will, therefore, be a charge to the consolidated statement of profit or loss in Q1 of 2025. On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective for all accounting periods starting on or after 31 December 2023. The adoption of this has not had a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate. The Group has applied the exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and, therefore, there is no impact on the tax values reported", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-483": { "value": "28. Taxation
2023
2024
Restated
1
$\u2019000 $\u2019000
Current tax
Current corporation tax charge
(17,746)
(39,308)
Current EPL tax charge
(221,420)
(333,425)
True-up in respect of prior years
30,573
(17,426)
Total current tax charge
(208,593)
(390,159)
Deferred tax
True-up in respect of prior years
(21,068)
6,370
Group tax (charge)/credit in consolidated statement of profit or loss
(1,905)
304,279
Group tax credit/(charge) in consolidated statement of other comprehensive income
195,642
(71,700)
Total deferred tax credit
172,669
238,949
Deferred Petroleum Revenue Tax
Deferred PRT credit in statement of profit or loss
50,381
70,037
Total tax charge through consolidated statement of profit or loss
(181,186)
(9,473)
1 See note 2. The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:
2023
2024
Restated
1
$\u2019000 $\u2019000
Accounting profit before tax
334,339
302,027
At tax rate of 40% (2023: 40%)
(133,735)
(120,811)
Non-deductible expense
8,700
(34,578)
Financing costs not allowed for SCT
(13,581)
(704)
Ring Fence Expenditure Supplement
14,340
102,866
Deferred tax effect of investment allowance
33,219
56,930
True-up in respect of prior years
9,504
(11,673)
Deferred PRT net of corporation tax
30,229
42,022
Deferred tax on EPL
119,102
292,829
Current tax on EPL
(221,420)
(333,425)
Income taxed at different rates
(27,956)
\u2013
Share-based payments
412
1,945
Unrecognised tax losses
\u2013
(4,874)
Total tax charge recorded in the consolidated statement of profit or loss
(181,186)
(9,473)
1 See note 2. The Company is UK tax resident. The effective rate of tax applicable for UK ring fence oil and gas activities in both 2024 and 2023 was 40% (excluding the Energy Profits Levy), consisting of a Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include interest income taxed at non-oil and gas tax rate of 25%, true-ups in respect of prior years resulting from filing of prior year tax returns, a 10% uplift on ring fence losses, Ring Fence Expenditure Supplement increasing the losses available to offset future profits subject to Ring Fence Corporation Tax and Supplementary Charge. In addition, investment allowance, a 62.5% uplift on capital expenditure, is available reducing the profits subject to the supplementary charge only. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK, however, adjustments to recognised deferred PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The Energy Profits Levy was enacted on 14 July 2022 with further changes announced on 17 November 2022 such that the Levy was increased to 35% from 1 January 2023 until 31 March 2028 increasing the effective UK ring fence oil and gas tax rate to 75%. On 6 March 2024, it was announced that EPL will be extended by one year to 31 March 2029 and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024. The impact of this was a charge to the consolidated statement of profit or loss of $58.1 million (2023: $nil) in the year to 31 December 2024. The extensions to 31 March 2029 and 31 March 2030 had not been substantively enacted at 31 December 2024 and are, therefore, not reflected in the results for the year ended 31 December 2024. Deferred tax at 31 December relates to the following:
2023
2024
Restated
1
$\u2019000 $\u2019000
Deferred corporation tax liability
(2,197,590)
(1,868,022)
Deferred corporation tax asset
3,279,585
2,480,921
Deferred PRT asset
142,141
91,758
Net deferred tax asset
1,224,136
704,657
Deferred tax assets primarily relate to decommissioning liabilities, brought forward tax losses and accumulated losses and profits related to derivative contracts. Deferred tax liabilities primarily relate to accelerated capital allowances on property, plant and equipment and accumulated losses and profits related to derivative contracts. Deferred tax balances are presented net as they arise in the same jurisdiction and the Group has a legally-enforceable right to offset as well as an intention to settle on a net basis. There are unrecognised allowances of up to circa $150 million that have no expiry date and could be recognised in future periods if future revenue from oil and gas activities increases and/ or further actions are undertaken. Non-oil and gas losses of $217 million (2023: $251 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses. The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:
2023
2024
Restated
1
$\u2019000 $\u2019000
At 1 January
704,657
392,457
Profit or loss credit
27,408
380,686
Other comprehensive income credit/(charge)
195,643
(71,700)
Deferred tax on decommissioning reimbursements (note 11)
(916)
3,214
Business combinations (note 17)
297,344
\u2013
At 31 December
1,224,136
704,657
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income, excluding PRT, relates to the following:
2023
2024
Restated
1
$\u2019000 $\u2019000
Accelerated capital allowances
100,974
515,277
Tax losses
(203,307)
(216,937)
Decommissioning provision
61,685
52,440
Deferred PRT
(20,153)
(28,015)
Hedging
2
201,534
(101,744)
Share schemes
963
3,978
Investment allowances
30,973
13,950
172,669
238,949
1 See note 2. 2 Hedging relates to deferred tax on derivatives designated in cash flow hedges and used for economic hedges
Deferred
corporation tax on Accelerated tax
Hedges deferred PRT depreciation Total
Gross deferred corporation tax liabilities $\u2019000 $\u2019000 $\u2019000 $\u2019000
At 1 January 2023
\u2013
(8,688)
(2,250,125)
(2,258,813)
Reclassification from deferred corporation tax assets
(8,678)
\u2013
\u2013
(8,678)
True-up in respect of prior years
2,721
\u2013
8,307
11,028
Origination and reversal of temporary differences
(101,744)
(28,015)
441,281
311,522
At 31 December 2023 as previously stated
(107,701)
(36,703)
(1,800,537)
(1,944,941)
Prior period adjustment (note 2)
\u2013
\u2013
76,919
76,919
At 31 December 2023 and 1 January 2024 as restated
(107,701)
(36,703)
(1,723,618)
(1,868,022)
Business combinations (note 17)
\u2013
\u2013
(549,062)
(549,062)
True-up in respect of prior years
\u2013
\u2013
(16,027)
(16,027)
Origination and reversal of temporary differences
201,534
(20,153)
147,973
329,354
Reclassification to deferred corporation tax assets
(93,833)
\u2013
\u2013
(93,833)
At 31 December 2024
\u2013
(56,856)
(2,140,734)
(2,197,590)
Decommissioning
Share schemes provision Other provisions Tax losses Hedges Total
Gross deferred corporation tax assets $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
At 1 January 2023
\u2013
666,052
\u2013
1,972,174
(8,678)
2,629,548
True-up in respect of prior years
177
\u2013
\u2013
(4,989)
\u2013
(4,812)
Reclassification to deferred corporation tax liabilities
\u2013
\u2013
\u2013
\u2013
8,678
8,678
Origination and reversal of temporary differences
3,802
55,654
\u2013
(211,949)
\u2013
(152,493)
At 31 December 2023 and 1 January 2024
3,979
721,706
\u2013
1,755,236
\u2013
2,480,921
Business combinations (note 17)
\u2013
257,392
21,350
567,666
\u2013
846,408
True-up in respect of prior years
\u2013
(8)
\u2013
(5,033)
\u2013
(5,041)
Origination and reversal of temporary differences
962
60,776
\u2013
(198,274)
\u2013
(136,536)
Reclassification from deferred corporation tax liabilities
\u2013
\u2013
\u2013
\u2013
93,833
93,833
At 31 December 2024
4,941
1,039,866
21,350
2,119,595
93,833
3,279,585
Total
Deferred PRT asset $\u2019000
At 1 January 2023
21,721
Origination and reversal of temporary differences
70,037
At 31 December 2023 and 1 January 2024
91,758
Origination and reversal of temporary differences
50,381
At 31 December 2024
142,141
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2024 of $1,082 million and $142 million, respectively (2023: $613 million and $92 million, respectively) are supported by estimates
of the Group\u2019s future taxable income, based on the same price and cost assumptions as used for impairment testing. The Group has undertaken and will undertake further restructuring exercises to move certain assets between Group
entities. Existing restructuring exercises have now been substantially completed. The recoverability of the deferred corporation tax asset is supported by this restructuring. The DTA relating to losses within the Group are expected to
unwind against taxable profits before the end of 2029.
An EPL (or \u2018Levy\u2019) was enacted on 14 July 2022, applying a Levy of 25% to the profits of oil and gas companies until 31 December 2025 or earlier if prices return to normalised levels. On 17 November 2022, the Levy was increased
to 35% and extended to 31 March 2028 regardless of oil and gas prices. The Levy is charged on oil and gas profits calculated on the same basis as Ring Fence Corporation Tax (RFCT), however, excludes relief for decommissioning and
finance costs. RFCT losses and investment allowance are not available to offset the EPL. On 9 June 2023 an Energy Security Investment Mechanism price floor was announced which would remove the EPL if both average oil and gas
prices fall to, or below, $71.40 per barrel for oil and \u00a30.54 per therm for gas, for two consecutive quarters. It is not currently forecast that this price floor will be met for both oil and gas prices and, therefore, there is currently no impact
from this on tax carrying values. On 6 March 2024, an extension of the Levy until 31 March 2029 was announced and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would
increase from 35% to 38% from 1 November 2024, of which only the rate increase had been enacted at 31 December 2024. Had the two-year extension to 31 March 2030 been enacted at 31 December 2024, this would have reduced
the net deferred tax asset by $318 million. This extension was substantively enacted on 3 March 2025 and will, therefore, be a charge to the consolidated statement of profit or loss in Q1 of 2025.
On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective
for all accounting periods starting on or after 31 December 2023. The adoption of this has not had a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate. The Group has applied the
exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and, therefore, there is no impact on the tax values reported.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-467": { "value": "28. Taxation
2023
2024
Restated
1
$\u2019000 $\u2019000
Current tax
Current corporation tax charge
(17,746)
(39,308)
Current EPL tax charge
(221,420)
(333,425)
True-up in respect of prior years
30,573
(17,426)
Total current tax charge
(208,593)
(390,159)
Deferred tax
True-up in respect of prior years
(21,068)
6,370
Group tax (charge)/credit in consolidated statement of profit or loss
(1,905)
304,279
Group tax credit/(charge) in consolidated statement of other comprehensive income
195,642
(71,700)
Total deferred tax credit
172,669
238,949
Deferred Petroleum Revenue Tax
Deferred PRT credit in statement of profit or loss
50,381
70,037
Total tax charge through consolidated statement of profit or loss
(181,186)
(9,473)
1 See note 2. The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:
2023
2024
Restated
1
$\u2019000 $\u2019000
Accounting profit before tax
334,339
302,027
At tax rate of 40% (2023: 40%)
(133,735)
(120,811)
Non-deductible expense
8,700
(34,578)
Financing costs not allowed for SCT
(13,581)
(704)
Ring Fence Expenditure Supplement
14,340
102,866
Deferred tax effect of investment allowance
33,219
56,930
True-up in respect of prior years
9,504
(11,673)
Deferred PRT net of corporation tax
30,229
42,022
Deferred tax on EPL
119,102
292,829
Current tax on EPL
(221,420)
(333,425)
Income taxed at different rates
(27,956)
\u2013
Share-based payments
412
1,945
Unrecognised tax losses
\u2013
(4,874)
Total tax charge recorded in the consolidated statement of profit or loss
(181,186)
(9,473)
1 See note 2. The Company is UK tax resident. The effective rate of tax applicable for UK ring fence oil and gas activities in both 2024 and 2023 was 40% (excluding the Energy Profits Levy), consisting of a Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include interest income taxed at non-oil and gas tax rate of 25%, true-ups in respect of prior years resulting from filing of prior year tax returns, a 10% uplift on ring fence losses, Ring Fence Expenditure Supplement increasing the losses available to offset future profits subject to Ring Fence Corporation Tax and Supplementary Charge. In addition, investment allowance, a 62.5% uplift on capital expenditure, is available reducing the profits subject to the supplementary charge only. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK, however, adjustments to recognised deferred PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The Energy Profits Levy was enacted on 14 July 2022 with further changes announced on 17 November 2022 such that the Levy was increased to 35% from 1 January 2023 until 31 March 2028 increasing the effective UK ring fence oil and gas tax rate to 75%. On 6 March 2024, it was announced that EPL will be extended by one year to 31 March 2029 and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024. The impact of this was a charge to the consolidated statement of profit or loss of $58.1 million (2023: $nil) in the year to 31 December 2024. The extensions to 31 March 2029 and 31 March 2030 had not been substantively enacted at 31 December 2024 and are, therefore, not reflected in the results for the year ended 31 December 2024. Deferred tax at 31 December relates to the following:
2023
2024
Restated
1
$\u2019000 $\u2019000
Deferred corporation tax liability
(2,197,590)
(1,868,022)
Deferred corporation tax asset
3,279,585
2,480,921
Deferred PRT asset
142,141
91,758
Net deferred tax asset
1,224,136
704,657
Deferred tax assets primarily relate to decommissioning liabilities, brought forward tax losses and accumulated losses and profits related to derivative contracts. Deferred tax liabilities primarily relate to accelerated capital allowances on property, plant and equipment and accumulated losses and profits related to derivative contracts. Deferred tax balances are presented net as they arise in the same jurisdiction and the Group has a legally-enforceable right to offset as well as an intention to settle on a net basis. There are unrecognised allowances of up to circa $150 million that have no expiry date and could be recognised in future periods if future revenue from oil and gas activities increases and/ or further actions are undertaken. Non-oil and gas losses of $217 million (2023: $251 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses. The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:
2023
2024
Restated
1
$\u2019000 $\u2019000
At 1 January
704,657
392,457
Profit or loss credit
27,408
380,686
Other comprehensive income credit/(charge)
195,643
(71,700)
Deferred tax on decommissioning reimbursements (note 11)
(916)
3,214
Business combinations (note 17)
297,344
\u2013
At 31 December
1,224,136
704,657
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income, excluding PRT, relates to the following:
2023
2024
Restated
1
$\u2019000 $\u2019000
Accelerated capital allowances
100,974
515,277
Tax losses
(203,307)
(216,937)
Decommissioning provision
61,685
52,440
Deferred PRT
(20,153)
(28,015)
Hedging
2
201,534
(101,744)
Share schemes
963
3,978
Investment allowances
30,973
13,950
172,669
238,949
1 See note 2. 2 Hedging relates to deferred tax on derivatives designated in cash flow hedges and used for economic hedges
Deferred
corporation tax on Accelerated tax
Hedges deferred PRT depreciation Total
Gross deferred corporation tax liabilities $\u2019000 $\u2019000 $\u2019000 $\u2019000
At 1 January 2023
\u2013
(8,688)
(2,250,125)
(2,258,813)
Reclassification from deferred corporation tax assets
(8,678)
\u2013
\u2013
(8,678)
True-up in respect of prior years
2,721
\u2013
8,307
11,028
Origination and reversal of temporary differences
(101,744)
(28,015)
441,281
311,522
At 31 December 2023 as previously stated
(107,701)
(36,703)
(1,800,537)
(1,944,941)
Prior period adjustment (note 2)
\u2013
\u2013
76,919
76,919
At 31 December 2023 and 1 January 2024 as restated
(107,701)
(36,703)
(1,723,618)
(1,868,022)
Business combinations (note 17)
\u2013
\u2013
(549,062)
(549,062)
True-up in respect of prior years
\u2013
\u2013
(16,027)
(16,027)
Origination and reversal of temporary differences
201,534
(20,153)
147,973
329,354
Reclassification to deferred corporation tax assets
(93,833)
\u2013
\u2013
(93,833)
At 31 December 2024
\u2013
(56,856)
(2,140,734)
(2,197,590)
Decommissioning
Share schemes provision Other provisions Tax losses Hedges Total
Gross deferred corporation tax assets $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
At 1 January 2023
\u2013
666,052
\u2013
1,972,174
(8,678)
2,629,548
True-up in respect of prior years
177
\u2013
\u2013
(4,989)
\u2013
(4,812)
Reclassification to deferred corporation tax liabilities
\u2013
\u2013
\u2013
\u2013
8,678
8,678
Origination and reversal of temporary differences
3,802
55,654
\u2013
(211,949)
\u2013
(152,493)
At 31 December 2023 and 1 January 2024
3,979
721,706
\u2013
1,755,236
\u2013
2,480,921
Business combinations (note 17)
\u2013
257,392
21,350
567,666
\u2013
846,408
True-up in respect of prior years
\u2013
(8)
\u2013
(5,033)
\u2013
(5,041)
Origination and reversal of temporary differences
962
60,776
\u2013
(198,274)
\u2013
(136,536)
Reclassification from deferred corporation tax liabilities
\u2013
\u2013
\u2013
\u2013
93,833
93,833
At 31 December 2024
4,941
1,039,866
21,350
2,119,595
93,833
3,279,585
Total
Deferred PRT asset $\u2019000
At 1 January 2023
21,721
Origination and reversal of temporary differences
70,037
At 31 December 2023 and 1 January 2024
91,758
Origination and reversal of temporary differences
50,381
At 31 December 2024
142,141
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2024 of $1,082 million and $142 million, respectively (2023: $613 million and $92 million, respectively) are supported by estimates of the Group\u2019s future taxable income, based on the same price and cost assumptions as used for impairment testing. The Group has undertaken and will undertake further restructuring exercises to move certain assets between Group entities. Existing restructuring exercises have now been substantially completed. The recoverability of the deferred corporation tax asset is supported by this restructuring. The DTA relating to losses within the Group are expected to unwind against taxable profits before the end of 2029. An EPL (or \u2018Levy\u2019) was enacted on 14 July 2022, applying a Levy of 25% to the profits of oil and gas companies until 31 December 2025 or earlier if prices return to normalised levels. On 17 November 2022, the Levy was increased to 35% and extended to 31 March 2028 regardless of oil and gas prices. The Levy is charged on oil and gas profits calculated on the same basis as Ring Fence Corporation Tax (RFCT), however, excludes relief for decommissioning and finance costs. RFCT losses and investment allowance are not available to offset the EPL. On 9 June 2023 an Energy Security Investment Mechanism price floor was announced which would remove the EPL if both average oil and gas prices fall to, or below, $71.40 per barrel for oil and \u00a30.54 per therm for gas, for two consecutive quarters. It is not currently forecast that this price floor will be met for both oil and gas prices and, therefore, there is currently no impact from this on tax carrying values. On 6 March 2024, an extension of the Levy until 31 March 2029 was announced and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024, of which only the rate increase had been enacted at 31 December 2024. Had the two-year extension to 31 March 2030 been enacted at 31 December 2024, this would have reduced the net deferred tax asset by $318 million. This extension was substantively enacted on 3 March 2025 and will, therefore, be a charge to the consolidated statement of profit or loss in Q1 of 2025. On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective for all accounting periods starting on or after 31 December 2023. The adoption of this has not had a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate. The Group has applied the exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and, therefore, there is no impact on the tax values reported", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-468": { "value": "
29. Commitments and contingencies
2024 2023
$\u2019000 $\u2019000
Capital commitments
Capital commitments incurred jointly with other venturers (Group\u2019s share)
399,613
506,959
The Group\u2019s capital expenditure is driven largely by full-phase expenditure on existing producing fields, new development projects and appraisal and development activities. As of 31 December 2024, the Group had commitments
for future capital expenditure amounting to $400 million (2023: $507 million). The key component of this relates to the Rosebank development at both dates. There are also commitments in relation to AFEs (authorisations for
expenditure) signed for activities on Captain enhanced oil extraction at both dates.
Contingencies
The Group enters into letters of credit and surety bonds to provide security for the Group\u2019s obligations under certain field and bi-lateral decommissioning security agreements, or equivalent, Sullom Voe Terminal Tariff Agreements
and deferred payment obligations. The instruments are either held by the Law Debenture Trust Corporation P.L.C. under a trust deed or EnQuest Heather Limited, as SVT Terminal Operator. At 31 December 2024, the Group had
$822 million (31 December 2023: $450 million) in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-432": { "value": "29. Commitments and contingencies
2024 2023
$\u2019000 $\u2019000
Capital commitments
Capital commitments incurred jointly with other venturers (Group\u2019s share)
399,613
506,959
The Group\u2019s capital expenditure is driven largely by full-phase expenditure on existing producing fields, new development projects and appraisal and development activities. As of 31 December 2024, the Group had commitments for future capital expenditure amounting to $400 million (2023: $507 million). The key component of this relates to the Rosebank development at both dates. There are also commitments in relation to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction at both dates. Contingencies The Group enters into letters of credit and surety bonds to provide security for the Group\u2019s obligations under certain field and bi-lateral decommissioning security agreements, or equivalent, Sullom Voe Terminal Tariff Agreements and deferred payment obligations. The instruments are either held by the Law Debenture Trust Corporation P.L.C. under a trust deed or EnQuest Heather Limited, as SVT Terminal Operator. At 31 December 2024, the Group had $822 million (31 December 2023: $450 million) in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements.", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-484": { "value": "29. Commitments and contingencies
2024 2023
$\u2019000 $\u2019000
Capital commitments
Capital commitments incurred jointly with other venturers (Group\u2019s share)
399,613
506,959
The Group\u2019s capital expenditure is driven largely by full-phase expenditure on existing producing fields, new development projects and appraisal and development activities. As of 31 December 2024, the Group had commitments for future capital expenditure amounting to $400 million (2023: $507 million). The key component of this relates to the Rosebank development at both dates. There are also commitments in relation to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction at both dates. Contingencies The Group enters into letters of credit and surety bonds to provide security for the Group\u2019s obligations under certain field and bi-lateral decommissioning security agreements, or equivalent, Sullom Voe Terminal Tariff Agreements and deferred payment obligations. The instruments are either held by the Law Debenture Trust Corporation P.L.C. under a trust deed or EnQuest Heather Limited, as SVT Terminal Operator. At 31 December 2024, the Group had $822 million (31 December 2023: $450 million) in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements.", "dimensions": { "concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-496": { "value": "30. Financial instruments To estimate the fair value of financial instruments, the Group uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilise observable market data. In addition to market information, the Group incorporates transaction specific details that market participants would utilise in a fair value measurement, including the impact of non-performance risk. The Group characterises inputs used in determining fair value using a hierarchy that prioritises inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realised or settled in a current market transaction. The three levels of the fair value hierarchy are as follows: \u2022 Level 1 \u2013 inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. \u2022 Level 2 \u2013 inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates and volatility factors, which can be observed or corroborated in the marketplace. The Group obtains information from sources such as the New York Mercantile Exchange and independent price publications. \u2022 Level 3 \u2013 inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument\u2019s fair value. In forming estimates, the Group utilises the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorised based upon the lowest level of input that is significant to the fair value measurement. The valuation of over-the-counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorised as Level 2. Gains or losses on financial instruments, that are not hedge accounted for, are recorded through the 'other gains' line in the consolidated statement of profit or loss. Credit valuation adjustments (CVA) and debit valuation adjustments (DVA) are calculated for each trade using two key inputs, being future exposures and credit spreads (incorporating both probability of default and loss given default). Future exposures have been estimated using an expected exposure- based approach over the lifetime of the trades. For the risk associated with counterparties, the credit spread is calculated using market observable credit default spreads. For the own credit risk, the credit spread is calculated using reference to a senior unsecured quoted publicly traded bond of the Group using appropriate tenor adjustments, except for out-of-the-money derivatives with counterparties which are in the Group\u2019s RBL. These derivatives rank higher than those with other counterparties as they are fully secured as part of the RBL agreement. Therefore, for the own risk credit risk adjustment (DVA) it has been estimated that the loss given default is zero and hence there is no DVA recognised for those derivatives which are with counterparties of the RBL. All of the Group\u2019s assets are pledged as security against borrowings. The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2024 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through profit in hedge Total carrying
amortised cost or loss relationships amount
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Financial assets
Cash and cash equivalents
165,123
\u2013
\u2013
165,123
Other financial assets
11,317
\u2013
\u2013
11,317
Trade and other receivables \u2013 excluding VAT receivable
411,056
\u2013
\u2013
411,056
Derivative financial instruments
\u2013
\u2013
32,962
32,962
Financial liabilities
Borrowings
(1,024,948)
\u2013
\u2013
(1,024,948)
Trade and other payables \u2013 excluding deferred income, inventory overlift and bonus/holiday pay accruals
(439,674)
\u2013
\u2013
(439,674)
Lease liability
(40,159)
\u2013
\u2013
(40,159)
Contingent and deferred consideration
(272,758)
(240,491)
\u2013
(513,249)
Derivative financial instruments
\u2013
(7,484)
(143,979)
(151,463)
(1,549,035)
The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2023 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through profit in hedge Total carrying
amortised cost or loss relationships amount
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Financial assets
Cash and cash equivalents
153,215
\u2013
\u2013
153,215
Trade and other receivables \u2013 excluding VAT receivable
330,351
\u2013
\u2013
330,351
Derivative financial instruments
\u2013
2,782
154,525
157,307
Financial liabilities
Borrowings
(748,151)
\u2013
\u2013
(748,151)
Trade and other payables \u2013 excluding deferred income, inventory overlift and bonus/holiday pay accruals
(343,279)
\u2013
\u2013
(343,279)
Lease liability
(20,559)
\u2013
\u2013
(20,559)
Contingent and deferred consideration
(63,979)
(296,390)
\u2013
(360,369)
Derivative financial instruments
(10,373)
(3,335)
(13,708)
(845,193)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2024:
Level 1 Level 2 Level 3 Total Fair Value
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Contingent consideration (note 26)
\u2013
(1,165)
(239,326)
(240,491)
Derivative financial instrument asset
\u2013
32,962
\u2013
32,962
Derivative financial instrument liability
\u2013
(151,463)
\u2013
(151,463)
Movements in level 3 financial instruments in the 12 months to 31 December 2024 were as follows:
$\u2019000
At 1 January 2024
(272,351)
Cash settlements
14,995
Changes in fair value
18,030
At 31 December 2024
(239,326)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2023:
Level 1 Level 2 Level 3 Total Fair Value
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Contingent consideration (note 26)
\u2013
(24,039)
(272,351)
(296,390)
Derivative financial instrument asset
\u2013
157,307
\u2013
157,307
Derivative financial instrument liability
\u2013
(13,708)
\u2013
(13,708)
Movements in level 3 financial instruments in the 12 months to 31 December 2023 were as follows:
$\u2019000
At 1 January 2023
(223,246)
Additions
(26,872)
Accretion
(8,799)
Changes in fair value
(13,434)
At 31 December 2023
(272,351)
Level 3 contingent consideration is valued on a discounted cash flow basis with the key inputs being commodity prices, the probability of certain future events occurring (\u2018trigger events\u2019) and the discount rate. The forecast cash flows are discounted at a rate of 6.33% (31 December 2023: 4.6%). Management has considered alternative scenarios to assess the valuation of the contingent consideration including, but not limited to, the key accounting estimate relating to the oil price. A reduction or increase in the price assumptions of 20% are considered to be reasonably possible changes. A 20% reduction in the oil price would result in a decrease in contingent consideration of $nil million (31 December 2023: $23.3 million) as the forecast price is already at a level which is lower than the trigger price. A 20% increase in the oil price would lead to an increase in contingent consideration of $21.7 million (31 December 2023: $41.0 million). The following table summarises the sensitivity of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date resulting from a 20% change in the probability of a trigger event occurring, risking of project and conditions being met for payment of contingent consideration, with all other variables held constant. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in probability $\u2019000 $\u2019000
20% decrease in probability
84,245
97,119
20% increase in probability
(77,051)
(84,086)
The following table summarises the sensitivity of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date resulting from a 1% decrease in discount rate, with all other variables held constant. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in discount rate $\u2019000 $\u2019000
1% decrease in discount rate
(5,707)
(5,284)
A 1% increase in discount rate would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. Financial instruments of the Group consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in the financial statements. At 31 December 2024 and 31 December 2023, financial instruments and the carrying amounts reported on the balance sheet approximates the fair values with the exception of borrowings. The carrying amount of borrowing is at amortised cost of $1,024.9 million (2023: $748.2 million) and the equivalent fair value is $1,025.5 million (2023: $781.4 million) that was categorised as level 3 in the fair value hierarchy level. Equivalent fair value was calculated using discounted cash flow method. The unobservable input is adjustment due to credit risk to risk free rates. The table below presents the gain on financial instruments that has been recognised in the consolidated statement of profit or loss as disclosed in note 8.
2024 2023
$\u2019000 $\u2019000
Revaluation of forex forward contracts
(1,310)
7,313
Revaluation of interest rate swaps
(637)
(6,488)
Revaluation of commodity hedges
2,291
42,006
Total revaluation gain on financial instruments
344
42,831
Realised gains/(losses) on forex forward contracts
5,760
(6,282)
Realised gains on interest rate swaps
638
6,967
Realised losses on commodity hedges
(1,575)
(457)
Total gain on financial instruments (note 8)
5,167
43,059
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-469": { "value": "30. Financial instruments To estimate the fair value of financial instruments, the Group uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilise observable market data. In addition to market information, the Group incorporates transaction specific details that market participants would utilise in a fair value measurement, including the impact of non-performance risk. The Group characterises inputs used in determining fair value using a hierarchy that prioritises inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realised or settled in a current market transaction. The three levels of the fair value hierarchy are as follows: \u2022 Level 1 \u2013 inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. \u2022 Level 2 \u2013 inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates and volatility factors, which can be observed or corroborated in the marketplace. The Group obtains information from sources such as the New York Mercantile Exchange and independent price publications. \u2022 Level 3 \u2013 inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument\u2019s fair value. In forming estimates, the Group utilises the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorised based upon the lowest level of input that is significant to the fair value measurement. The valuation of over-the-counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorised as Level 2. Gains or losses on financial instruments, that are not hedge accounted for, are recorded through the 'other gains' line in the consolidated statement of profit or loss. Credit valuation adjustments (CVA) and debit valuation adjustments (DVA) are calculated for each trade using two key inputs, being future exposures and credit spreads (incorporating both probability of default and loss given default). Future exposures have been estimated using an expected exposure- based approach over the lifetime of the trades. For the risk associated with counterparties, the credit spread is calculated using market observable credit default spreads. For the own credit risk, the credit spread is calculated using reference to a senior unsecured quoted publicly traded bond of the Group using appropriate tenor adjustments, except for out-of-the-money derivatives with counterparties which are in the Group\u2019s RBL. These derivatives rank higher than those with other counterparties as they are fully secured as part of the RBL agreement. Therefore, for the own risk credit risk adjustment (DVA) it has been estimated that the loss given default is zero and hence there is no DVA recognised for those derivatives which are with counterparties of the RBL. All of the Group\u2019s assets are pledged as security against borrowings. The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2024 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through profit in hedge Total carrying
amortised cost or loss relationships amount
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Financial assets
Cash and cash equivalents
165,123
\u2013
\u2013
165,123
Other financial assets
11,317
\u2013
\u2013
11,317
Trade and other receivables \u2013 excluding VAT receivable
411,056
\u2013
\u2013
411,056
Derivative financial instruments
\u2013
\u2013
32,962
32,962
Financial liabilities
Borrowings
(1,024,948)
\u2013
\u2013
(1,024,948)
Trade and other payables \u2013 excluding deferred income, inventory overlift and bonus/holiday pay accruals
(439,674)
\u2013
\u2013
(439,674)
Lease liability
(40,159)
\u2013
\u2013
(40,159)
Contingent and deferred consideration
(272,758)
(240,491)
\u2013
(513,249)
Derivative financial instruments
\u2013
(7,484)
(143,979)
(151,463)
(1,549,035)
The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2023 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through profit in hedge Total carrying
amortised cost or loss relationships amount
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Financial assets
Cash and cash equivalents
153,215
\u2013
\u2013
153,215
Trade and other receivables \u2013 excluding VAT receivable
330,351
\u2013
\u2013
330,351
Derivative financial instruments
\u2013
2,782
154,525
157,307
Financial liabilities
Borrowings
(748,151)
\u2013
\u2013
(748,151)
Trade and other payables \u2013 excluding deferred income, inventory overlift and bonus/holiday pay accruals
(343,279)
\u2013
\u2013
(343,279)
Lease liability
(20,559)
\u2013
\u2013
(20,559)
Contingent and deferred consideration
(63,979)
(296,390)
\u2013
(360,369)
Derivative financial instruments
(10,373)
(3,335)
(13,708)
(845,193)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2024:
Level 1 Level 2 Level 3 Total Fair Value
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Contingent consideration (note 26)
\u2013
(1,165)
(239,326)
(240,491)
Derivative financial instrument asset
\u2013
32,962
\u2013
32,962
Derivative financial instrument liability
\u2013
(151,463)
\u2013
(151,463)
Movements in level 3 financial instruments in the 12 months to 31 December 2024 were as follows:
$\u2019000
At 1 January 2024
(272,351)
Cash settlements
14,995
Changes in fair value
18,030
At 31 December 2024
(239,326)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2023:
Level 1 Level 2 Level 3 Total Fair Value
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Contingent consideration (note 26)
\u2013
(24,039)
(272,351)
(296,390)
Derivative financial instrument asset
\u2013
157,307
\u2013
157,307
Derivative financial instrument liability
\u2013
(13,708)
\u2013
(13,708)
Movements in level 3 financial instruments in the 12 months to 31 December 2023 were as follows:
$\u2019000
At 1 January 2023
(223,246)
Additions
(26,872)
Accretion
(8,799)
Changes in fair value
(13,434)
At 31 December 2023
(272,351)
Level 3 contingent consideration is valued on a discounted cash flow basis with the key inputs being commodity prices, the probability of certain future events occurring (\u2018trigger events\u2019) and the discount rate. The forecast cash flows are discounted at a rate of 6.33% (31 December 2023: 4.6%). Management has considered alternative scenarios to assess the valuation of the contingent consideration including, but not limited to, the key accounting estimate relating to the oil price. A reduction or increase in the price assumptions of 20% are considered to be reasonably possible changes. A 20% reduction in the oil price would result in a decrease in contingent consideration of $nil million (31 December 2023: $23.3 million) as the forecast price is already at a level which is lower than the trigger price. A 20% increase in the oil price would lead to an increase in contingent consideration of $21.7 million (31 December 2023: $41.0 million). The following table summarises the sensitivity of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date resulting from a 20% change in the probability of a trigger event occurring, risking of project and conditions being met for payment of contingent consideration, with all other variables held constant. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in probability $\u2019000 $\u2019000
20% decrease in probability
84,245
97,119
20% increase in probability
(77,051)
(84,086)
The following table summarises the sensitivity of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date resulting from a 1% decrease in discount rate, with all other variables held constant. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in discount rate $\u2019000 $\u2019000
1% decrease in discount rate
(5,707)
(5,284)
A 1% increase in discount rate would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. Financial instruments of the Group consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in the financial statements. At 31 December 2024 and 31 December 2023, financial instruments and the carrying amounts reported on the balance sheet approximates the fair values with the exception of borrowings. The carrying amount of borrowing is at amortised cost of $1,024.9 million (2023: $748.2 million) and the equivalent fair value is $1,025.5 million (2023: $781.4 million) that was categorised as level 3 in the fair value hierarchy level. Equivalent fair value was calculated using discounted cash flow method. The unobservable input is adjustment due to credit risk to risk free rates. The table below presents the gain on financial instruments that has been recognised in the consolidated statement of profit or loss as disclosed in note 8.
2024 2023
$\u2019000 $\u2019000
Revaluation of forex forward contracts
(1,310)
7,313
Revaluation of interest rate swaps
(637)
(6,488)
Revaluation of commodity hedges
2,291
42,006
Total revaluation gain on financial instruments
344
42,831
Realised gains/(losses) on forex forward contracts
5,760
(6,282)
Realised gains on interest rate swaps
638
6,967
Realised losses on commodity hedges
(1,575)
(457)
Total gain on financial instruments (note 8)
5,167
43,059
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-485": { "value": "
Mandatorily Derivatives
measured at fair designated
Measured at value through profit in hedge Total carrying
amortised cost or loss relationships amount
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Financial assets
Cash and cash equivalents
165,123
\u2013
\u2013
165,123
Other financial assets
11,317
\u2013
\u2013
11,317
Trade and other receivables \u2013 excluding VAT receivable
411,056
\u2013
\u2013
411,056
Derivative financial instruments
\u2013
\u2013
32,962
32,962
Financial liabilities
Borrowings
(1,024,948)
\u2013
\u2013
(1,024,948)
Trade and other payables \u2013 excluding deferred income, inventory overlift and bonus/holiday pay accruals
(439,674)
\u2013
\u2013
(439,674)
Lease liability
(40,159)
\u2013
\u2013
(40,159)
Contingent and deferred consideration
(272,758)
(240,491)
\u2013
(513,249)
Derivative financial instruments
\u2013
(7,484)
(143,979)
(151,463)
(1,549,035)
The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2023 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through profit in hedge Total carrying
amortised cost or loss relationships amount
$\u2019000 $\u2019000 $\u2019000 $\u2019000
Financial assets
Cash and cash equivalents
153,215
\u2013
\u2013
153,215
Trade and other receivables \u2013 excluding VAT receivable
330,351
\u2013
\u2013
330,351
Derivative financial instruments
\u2013
2,782
154,525
157,307
Financial liabilities
Borrowings
(748,151)
\u2013
\u2013
(748,151)
Trade and other payables \u2013 excluding deferred income, inventory overlift and bonus/holiday pay accruals
(343,279)
\u2013
\u2013
(343,279)
Lease liability
(20,559)
\u2013
\u2013
(20,559)
Contingent and deferred consideration
(63,979)
(296,390)
\u2013
(360,369)
Derivative financial instruments
(10,373)
(3,335)
(13,708)
(845,193)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-470": { "value": "Cash flow hedge reserve The table below presents the movement in financial instruments that has been recognised through the statement of comprehensive income relating to the cash flow hedge reserve:
2024 2023
Cash flow hedge reserve $\u2019000 $\u2019000
At 1 January
39,818
16,710
Change in fair value of derivative instruments
(68,492)
358,141
Amounts recycled to revenue
(135,122)
(265,711)
Amounts recycled to operating costs
(8,738)
\u2013
Amounts recycled to dividends
(1,285)
\u2013
Amount per consolidated statement of comprehensive income
(213,637)
92,430
Deferred tax on movement in year
158,035
(69,322)
Cash flow hedge reserve at 31 December
(15,784)
39,818
Cost of hedging reserve The table below presents the movement in financial instruments that has been disclosed through the statement of comprehensive income relating to the cost of hedging reserve:
2024 2023
Cost of hedging reserve $\u2019000 $\u2019000
At 1 January
4,068
3,275
Change in fair value of the intrinsic value of derivative instruments
(55,744)
(12,269)
Amounts recycled to revenue \u2013 oil put premiums
1,697
11,850
Amounts recycled to revenue \u2013 gas put premiums
3,240
3,590
Amount per consolidated statement of comprehensive income
(50,807)
3,170
Deferred tax on movement in year
37,607
(2,378)
Cost of hedging reserve at 31 December
(9,132)
4,068
The Group has identified that it is exposed principally to these areas of market risk. 31. Derivative financial instruments The net carrying amount of each category of derivative is set out below:
2024 2023
$\u2019000 $\u2019000
Oil swaps \u2013 cash flow hedge
19,836
9,913
Oil collars \u2013 cash flow hedge
6,536
7,434
Gas swaps \u2013 cash flow hedge
(49,522)
47,232
Gas swaps \u2013 non-cash flow hedge
\u2013
(2,290)
Gas collars \u2013 cash flow hedge
(81,185)
89,944
Interest rate swaps \u2013 non-cash flow hedge
\u2013
637
FX forwards \u2013 cash flow hedge
214
(3,961)
FX forwards \u2013 non-cash flow hedge
(7,484)
\u2013
FX collars \u2013 cash flow hedge
(6,896)
(3,335)
FX collars \u2013 non-cash flow hedge
\u2013
(1,975)
(118,501)
143,599
2024 2023
Maturity analysis of derivative financial instruments $\u2019000 $\u2019000
Non-current assets
\u2013
17,810
Current assets
32,962
139,497
Non-current liabilities
(20,987)
\u2013
Current liabilities
(130,476)
(13,708)
(118,501)
143,599
The fair value of commodity derivatives is estimated using a net present value model (commodity swaps) or an appropriate option valuation model (options and collars). These contracts are valued using observable market pricing data including volatilities. A 20% reduction in future commodity prices, with all other assumptions held constant, would result in a decrease in the fair value of derivatives of $260 million (2023: $113 million). A 20% increase in future commodity prices, with all other assumptions held constant, would result in an increase in the intrinsic value of option derivative instruments at 31 December 2024 of $113 million (2023: $88 million). Derivative financial instruments that are with counterparties included within the RBL are subject to Master Netting Agreements, this includes the majority of the Group\u2019s derivative financial instruments as at 31 December 2024 and 2023. The terms of the Master Netting Arrangements create a legally enforceable right of offset that comes into effect only on the occurrence of a specified event of default or termination event or other events not expected to happen in the normal course of business. Although the Group has the ability to net settle certain transactions with certain counterparties where an election has been made, this is not considered to be significant at 31 December 2024. Accordingly, the Group has not offset any derivatives balances in the statement of financial position in any of the periods presented. Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2024 are detailed below:
Amount recognised in the Related amounts not set off in the
statement of financial position statement of financial position Net amount
$000 $000 $000
Derivative assets
32,962
(22,962)
10,000
Derivative liabilities
(151,463)
22,962
(128,501)
Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2023 are detailed below:
Amount recognised in the Related amounts not set off in the
statement of financial position statement of financial position Net amount
$000 $000 $000
Derivative assets
157,306
(4,436)
152,870
Derivative liabilities
(13,708)
4,436
(9,272)
", "dimensions": { "concept": "ifrs-full:DisclosureOfHedgeAccountingExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-486": { "value": "i) Commodity risk Commodity price risk related to crude oil prices is the Group\u2019s most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Group is also exposed to natural gas price movements on uncontracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions. The Group\u2019s expenditures are subject to the effects of inflation and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. The Group may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows. In all periods presented, the Group has designated certain commodity options as a cash flow hedge of highly probable sales. Because the critical terms (i.e. the quantity, maturity and underlying price) of the commodity option and their corresponding hedged items are the same, the Group performs a qualitative assessment of effectiveness and it is expected that the intrinsic value of the commodity option and the value of the corresponding hedged items will systematically change in opposite direction in response to movements in the price of underlying commodity if the price of the commodity increases above the strike price of the derivative. The main source of hedge ineffectiveness in these hedge relationships is the effect of the counterparty and the Group\u2019s own credit risk on the fair value of the option contracts, which is not reflected in the fair value of the hedged item and if the forecast transaction will happen earlier or later than originally expected. There was no hedge ineffectiveness in the current or prior year. The Group\u2019s target is to hedge oil and gas prices up to a maximum of 75% of the next 12 months\u2019 production on a rolling annual basis, up to 50% in the following 12-month period and 25% in the subsequent 12-month period. On a rolling basis, the Group has minimum and maximum hedging requirements under the RBL. The minimum requirements depend on levels of utilisation with reference to the latest borrowing base amount, as follows: \u2022 If drawn amounts under the loan tranche of the RBL are below 10%, no hedging is required; \u2022 If drawn amounts are above 10% but below 50%, the Group is required to hedge no less than 35% for the first 12 months and no less than 20% for the following 12 month period; and \u2022 If drawn amounts are equal to or greater than 50%, the Group is required to hedge no less than 50% for the first 12 months and no less than 30% for the following 12 month period. Maximum hedging volumes are set, on a rolling basis, at 85% for year one, 65% for year two, 50% for year three and 30% for year four, and 0% thereafter. The table below represents total commodity hedges in place at the 2024 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 25 - Dec 25
3,505,500
bbls
$78/bbl
Oil collars
Jan 25 - Dec 25
1,969,500
bbls
$74/bbl floor - $85/bbl ceiling
Gas swaps
Jan 25 - Dec 26
296,750,000
therms
98p/therm
Gas puts
Jan 25 - Dec 26
217,725,000
therms
81p/therm
Gas collars
Jan 25 - Dec 26
348,555,000
therms
83p/therm floor - 102p/therm ceiling
The table below represents total commodity hedges in place at the 2023 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 24 \u2013 Dec 24
1,931,500
bbls
$82/bbl
Oil collars
Jan 24 \u2013 Dec 24
2,744,000
bbls
$75/bbl floor \u2013 $87/bbl ceiling
Gas swaps
Jan 24 \u2013 Dec 24
53,175,000
therms
140p/therm
Gas swaps
Jan 25 \u2013 Sep 25
18,225,000
therms
120p/therm
Gas collars
Jan 24 \u2013 Dec 24
123,350,000
therms
135p/therm floor \u2013 210p/therm ceiling
Gas collars
Jan 25 \u2013 Mar 25
9,000,000
therms
130/therm floor \u2013 185p/therm ceiling
The following table summarises the sensitivity of a 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of commodity derivatives at the reporting date. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in realised commodity price $\u2019000 $\u2019000
20% decrease in realised oil price
(235,713)
(177,151)
20% decrease in realised gas price
(119,799)
(146,794)
A 20% increase in realised commodity prices would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. ii) Interest risk The calculation of interest payments for the RBL facility and the optional project capital expenditure facility incorporate SOFR. The Group is, therefore, exposed to interest rate risk to the extent that SOFR may fluctuate. The Group mitigates the risk of SOFR fluctuations by entering into interest rate swaps on floating rates. There were no interest rate financial instruments in place at either 31 December 2024 or 31 December 2023. The following table summarises the sensitivity of an increase of 250 basis points in SOFR, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary liabilities at the reporting date.
2024 2023
Change in interest rate $\u2019000 $\u2019000
Increase of 250 basis points
(8,369)
(22,370)
A decrease in 250 basis points in interest rates would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. iii) Foreign exchange rate risk The Group is exposed to foreign exchange risks to the extent it transacts in various currencies, while measuring and reporting its results in US Dollars. Since time passes between the recording of a receivable or payable transaction and its collection or payment, the Group is exposed to gains or losses on non-US Dollar amounts and on balance sheet translation of monetary accounts denominated in non-US Dollar amounts due to spot rate fluctuations from year-to-year. As at 31 December 2024, the Group had an average of \u00a321.3 million per quarter hedged at an average forward rate of $1.273:\u00a31 for the period January to December 2025. As at 31 December 2024, the Group had an average of \u00a349.5 million per quarter hedged at an average collar floor of $1.268:\u00a31 and average collar ceiling of $1.298:\u00a31 for the period January to December 2025. As at 31 December 2023, the Group had an average of \u00a310.2 million per quarter hedged at an average forward rate of $1.219:\u00a31 for the period January to December 2024. As at 31 December 2023, the Group had an average of \u00a330.3 million per quarter hedged at an average collar floor of $1.200:\u00a31 and average collar ceiling of $1.230:\u00a31 for the period January to December 2024. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is less significant.
2024 2023
Change in Sterling foreign exchange rate $\u2019000 $\u2019000
10% weakening of Sterling against the US Dollar (2023 revised as explained below)
(6,895)
(6,855)
In the 2023 Annual Report and Accounts, the Group incorrectly included non-monetary items denominated in Sterling to calculate the above sensitivity analysis. The correct impact on profit before tax was a loss of $7 million and not a loss of $123 million as disclosed previously. A 10% strengthening of Sterling against the US Dollar would have had the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. The Group's Sterling denominated monetary net assets at 31 December 2024 were \u00a355 million (2023: \u00a353.8 million). ", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-471": { "value": "i) Commodity risk Commodity price risk related to crude oil prices is the Group\u2019s most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Group is also exposed to natural gas price movements on uncontracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions. The Group\u2019s expenditures are subject to the effects of inflation and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. The Group may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows. In all periods presented, the Group has designated certain commodity options as a cash flow hedge of highly probable sales. Because the critical terms (i.e. the quantity, maturity and underlying price) of the commodity option and their corresponding hedged items are the same, the Group performs a qualitative assessment of effectiveness and it is expected that the intrinsic value of the commodity option and the value of the corresponding hedged items will systematically change in opposite direction in response to movements in the price of underlying commodity if the price of the commodity increases above the strike price of the derivative. The main source of hedge ineffectiveness in these hedge relationships is the effect of the counterparty and the Group\u2019s own credit risk on the fair value of the option contracts, which is not reflected in the fair value of the hedged item and if the forecast transaction will happen earlier or later than originally expected. There was no hedge ineffectiveness in the current or prior year. The Group\u2019s target is to hedge oil and gas prices up to a maximum of 75% of the next 12 months\u2019 production on a rolling annual basis, up to 50% in the following 12-month period and 25% in the subsequent 12-month period. On a rolling basis, the Group has minimum and maximum hedging requirements under the RBL. The minimum requirements depend on levels of utilisation with reference to the latest borrowing base amount, as follows: \u2022 If drawn amounts under the loan tranche of the RBL are below 10%, no hedging is required; \u2022 If drawn amounts are above 10% but below 50%, the Group is required to hedge no less than 35% for the first 12 months and no less than 20% for the following 12 month period; and \u2022 If drawn amounts are equal to or greater than 50%, the Group is required to hedge no less than 50% for the first 12 months and no less than 30% for the following 12 month period. Maximum hedging volumes are set, on a rolling basis, at 85% for year one, 65% for year two, 50% for year three and 30% for year four, and 0% thereafter.
The table below represents total commodity hedges in place at the 2024 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 25 - Dec 25
3,505,500
bbls
$78/bbl
Oil collars
Jan 25 - Dec 25
1,969,500
bbls
$74/bbl floor - $85/bbl ceiling
Gas swaps
Jan 25 - Dec 26
296,750,000
therms
98p/therm
Gas puts
Jan 25 - Dec 26
217,725,000
therms
81p/therm
Gas collars
Jan 25 - Dec 26
348,555,000
therms
83p/therm floor - 102p/therm ceiling
The table below represents total commodity hedges in place at the 2023 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 24 \u2013 Dec 24
1,931,500
bbls
$82/bbl
Oil collars
Jan 24 \u2013 Dec 24
2,744,000
bbls
$75/bbl floor \u2013 $87/bbl ceiling
Gas swaps
Jan 24 \u2013 Dec 24
53,175,000
therms
140p/therm
Gas swaps
Jan 25 \u2013 Sep 25
18,225,000
therms
120p/therm
Gas collars
Jan 24 \u2013 Dec 24
123,350,000
therms
135p/therm floor \u2013 210p/therm ceiling
Gas collars
Jan 25 \u2013 Mar 25
9,000,000
therms
130/therm floor \u2013 185p/therm ceiling
The following table summarises the sensitivity of a 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of commodity derivatives at the
reporting date. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in realised commodity price $\u2019000 $\u2019000
20% decrease in realised oil price
(235,713)
(177,151)
20% decrease in realised gas price
(119,799)
(146,794)
A 20% increase in realised commodity prices would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant.
ii) Interest risk
The calculation of interest payments for the RBL facility and the optional project capital expenditure facility incorporate SOFR. The Group is, therefore, exposed to interest rate risk to the extent that SOFR may fluctuate. The Group
mitigates the risk of SOFR fluctuations by entering into interest rate swaps on floating rates.
There were no interest rate financial instruments in place at either 31 December 2024 or 31 December 2023.
The following table summarises the sensitivity of an increase of 250 basis points in SOFR, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary liabilities at the reporting date.
2024 2023
Change in interest rate $\u2019000 $\u2019000
Increase of 250 basis points
(8,369)
(22,370)
A decrease in 250 basis points in interest rates would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. iii) Foreign exchange rate risk The Group is exposed to foreign exchange risks to the extent it transacts in various currencies, while measuring and reporting its results in US Dollars. Since time passes between the recording of a receivable or payable transaction and its collection or payment, the Group is exposed to gains or losses on non-US Dollar amounts and on balance sheet translation of monetary accounts denominated in non-US Dollar amounts due to spot rate fluctuations from year-to-year. As at 31 December 2024, the Group had an average of \u00a321.3 million per quarter hedged at an average forward rate of $1.273:\u00a31 for the period January to December 2025. As at 31 December 2024, the Group had an average of \u00a349.5 million per quarter hedged at an average collar floor of $1.268:\u00a31 and average collar ceiling of $1.298:\u00a31 for the period January to December 2025. As at 31 December 2023, the Group had an average of \u00a310.2 million per quarter hedged at an average forward rate of $1.219:\u00a31 for the period January to December 2024. As at 31 December 2023, the Group had an average of \u00a330.3 million per quarter hedged at an average collar floor of $1.200:\u00a31 and average collar ceiling of $1.230:\u00a31 for the period January to December 2024. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is less significant.
2024 2023
Change in Sterling foreign exchange rate $\u2019000 $\u2019000
10% weakening of Sterling against the US Dollar (2023 revised as explained below)
(6,895)
(6,855)
In the 2023 Annual Report and Accounts, the Group incorrectly included non-monetary items denominated in Sterling to calculate the above sensitivity analysis. The correct impact on profit before tax was a loss of $7 million and not a loss of $123 million as disclosed previously. A 10% strengthening of Sterling against the US Dollar would have had the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. The Group's Sterling denominated monetary net assets at 31 December 2024 were \u00a355 million (2023: \u00a353.8 million). iv) Credit risk The majority of the Group\u2019s trade and other receivables are with customers in the oil and gas industry and are subject to normal industry credit risks and are unsecured. Customers of the Group are mainly oil and gas majors with good credit ratings and low credit risk, including bp, Eni and Shell. The Group assesses partners\u2019 creditworthiness before entering into farm-in or joint venture agreements. In the past, the Group has not experienced credit loss in the collection of accounts receivable. As the Group\u2019s exploration, drilling and development activities expand with existing and new joint venture partners, the Group will assess and continuously update its management of associated credit risk and related procedures. The Group regularly monitors all customer receivable balances outstanding in excess of 90 days for ECLs. As at 31 December 2024, substantially all accounts receivables are current, being defined as less than 90 days. The Group has no allowance for doubtful accounts as at 31 December 2024 (31 December 2023: $nil). The Group may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The Group\u2019s exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date and these counterparties represent a very low risk of default. As at 31 December 2024, the Group\u2019s exposure is $nil (31 December 2023: $nil). Credit valuation adjustments (CVA) and debit valuation adjustments (DVA) are calculated for each trade using two key inputs, being future exposures and credit spreads (incorporating both probability of default and loss-given default). Future exposures have been estimated using an expected exposure-based approach over the lifetime of the trades. For the risk associated with counterparties, the credit spread is calculated using market observable credit default spreads. For the own credit risk, the credit spread is calculated using reference to a senior unsecured quoted publicly traded bond of the Group using appropriate tenor adjustments, except for out-of-the-money derivatives with counterparties which are in the Group\u2019s RBL. These derivatives rank higher than those with other counterparties as they are fully secured as part of the RBL agreement. Therefore for the own risk credit risk adjustment (DVA) it has been estimated that the loss given default is zero and hence there is no DVA recognised for those derivatives which are with counterparties of the RBL. The Group also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values. v) Liquidity risk Liquidity risk includes the risk that as a result of its operational liquidity requirements, the Group will not have sufficient funds to settle a transaction on the due date. The Group manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Group considers the maturity profiles of its financial assets and liabilities. As at 31 December 2023 and 2024, substantially all accounts payable are current. As borrowings are linked to SOFR, a spot rate at 31 December 2024 was used to calculate future borrowings cash flows. The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2024:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(439,674)
\u2013
\u2013
(439,674)
(439,674)
Contingent and deferred consideration
\u2013
(310,132)
(212,908)
(44,536)
(567,576)
(513,249)
Lease liabilities
5.69%
(21,046)
(21,876)
\u2013
(42,922)
(40,159)
Borrowings
8.14%
(85,462)
(1,356,881)
\u2013
(1,442,343)
(1,024,948)
(856,314)
(1,591,665)
(44,536)
(2,492,515)
(2,018,030)
The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2023:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(343,279)
\u2013
\u2013
(343,279)
(343,279)
Contingent and deferred consideration
\u2013
(101,669)
(248,388)
(44,508)
(394,565)
(360,369)
Lease liabilities
6.07%
(20,152)
(669)
\u2013
(20,821)
(20,559)
Borrowings
8.85%
(64,190)
(840,085)
\u2013
(904,275)
(748,151)
(529,290)
(1,089,142)
(44,508)
(1,662,940)
(1,472,358)
The following tables set out the details of the Group\u2019s liquidity analysis for its derivative financial instruments based on contractual maturities. The tables have been drawn up based on the undiscounted net cash inflows and outflows on derivative instruments that settle on a net basis, and the undiscounted gross inflows and outflows on those derivatives that require gross settlement. When the amount payable or receivable is not fixed, the amount disclosed has been determined by reference to the projected interest rates as illustrated by the yield curves existing at the reporting date.
Within Within
1 year 2 to 5 years Total
At 31 December 2024 $\u2019000 $\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(74,252)
(10,293)
(84,545)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(191,464)
\u2013
(191,464)
Foreign exchange collars \u2013 gross outflows
(191,074)
\u2013
(191,074)
(456,790)
(10,293)
(467,083)
Within Within
1 year 2 to 5 years Total
At 31 December 2023 $\u2019000 $\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(2,290)
\u2013
(2,290)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(113,342)
\u2013
(113,342)
Foreign exchange collars \u2013 gross outflows
(155,071)
\u2013
(155,071)
(270,703)
\u2013
(270,703)
vi) Capital management The Group\u2019s objectives when managing capital are to safeguard the Group\u2019s ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required. The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates eroding the Group\u2019s financial results. ", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialRiskManagementExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-497": { "value": "The following table summarises the sensitivity of a 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of commodity derivatives at the reporting date. The impact on equity is the same as the impact on profit before tax.
2024 2023
Change in realised commodity price $\u2019000 $\u2019000
20% decrease in realised oil price
(235,713)
(177,151)
20% decrease in realised gas price
(119,799)
(146,794)
A 20% increase in realised commodity prices would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. The following table summarises the sensitivity of an increase of 250 basis points in SOFR, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary liabilities at the reporting date.
2024 2023
Change in interest rate $\u2019000 $\u2019000
Increase of 250 basis points
(8,369)
(22,370)
A decrease in 250 basis points in interest rates would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is less significant.
2024 2023
Change in Sterling foreign exchange rate $\u2019000 $\u2019000
10% weakening of Sterling against the US Dollar (2023 revised as explained below)
(6,895)
(6,855)
In the 2023 Annual Report and Accounts, the Group incorrectly included non-monetary items denominated in Sterling to calculate the above sensitivity analysis. The correct impact on profit before tax was a loss of $7 million and not a loss of $123 million as disclosed previously. A 10% strengthening of Sterling against the US Dollar would have had the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. The Group's Sterling denominated monetary net assets at 31 December 2024 were \u00a355 million (2023: \u00a353.8 million). ", "dimensions": { "concept": "ifrs-full:SensitivityAnalysisForEachTypeOfMarketRisk", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-487": { "value": "iv) Credit risk The majority of the Group\u2019s trade and other receivables are with customers in the oil and gas industry and are subject to normal industry credit risks and are unsecured. Customers of the Group are mainly oil and gas majors with good credit ratings and low credit risk, including bp, Eni and Shell. The Group assesses partners\u2019 creditworthiness before entering into farm-in or joint venture agreements. In the past, the Group has not experienced credit loss in the collection of accounts receivable. As the Group\u2019s exploration, drilling and development activities expand with existing and new joint venture partners, the Group will assess and continuously update its management of associated credit risk and related procedures. The Group regularly monitors all customer receivable balances outstanding in excess of 90 days for ECLs. As at 31 December 2024, substantially all accounts receivables are current, being defined as less than 90 days. The Group has no allowance for doubtful accounts as at 31 December 2024 (31 December 2023: $nil). The Group may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The Group\u2019s exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date and these counterparties represent a very low risk of default. As at 31 December 2024, the Group\u2019s exposure is $nil (31 December 2023: $nil). Credit valuation adjustments (CVA) and debit valuation adjustments (DVA) are calculated for each trade using two key inputs, being future exposures and credit spreads (incorporating both probability of default and loss-given default). Future exposures have been estimated using an expected exposure-based approach over the lifetime of the trades. For the risk associated with counterparties, the credit spread is calculated using market observable credit default spreads. For the own credit risk, the credit spread is calculated using reference to a senior unsecured quoted publicly traded bond of the Group using appropriate tenor adjustments, except for out-of-the-money derivatives with counterparties which are in the Group\u2019s RBL. These derivatives rank higher than those with other counterparties as they are fully secured as part of the RBL agreement. Therefore for the own risk credit risk adjustment (DVA) it has been estimated that the loss given default is zero and hence there is no DVA recognised for those derivatives which are with counterparties of the RBL. The Group also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values. ", "dimensions": { "concept": "ifrs-full:DisclosureOfCreditRiskExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-488": { "value": "v) Liquidity risk Liquidity risk includes the risk that as a result of its operational liquidity requirements, the Group will not have sufficient funds to settle a transaction on the due date. The Group manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Group considers the maturity profiles of its financial assets and liabilities. As at 31 December 2023 and 2024, substantially all accounts payable are current. As borrowings are linked to SOFR, a spot rate at 31 December 2024 was used to calculate future borrowings cash flows. The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2024:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(439,674)
\u2013
\u2013
(439,674)
(439,674)
Contingent and deferred consideration
\u2013
(310,132)
(212,908)
(44,536)
(567,576)
(513,249)
Lease liabilities
5.69%
(21,046)
(21,876)
\u2013
(42,922)
(40,159)
Borrowings
8.14%
(85,462)
(1,356,881)
\u2013
(1,442,343)
(1,024,948)
(856,314)
(1,591,665)
(44,536)
(2,492,515)
(2,018,030)
The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2023:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate $\u2019000 $\u2019000 $\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(343,279)
\u2013
\u2013
(343,279)
(343,279)
Contingent and deferred consideration
\u2013
(101,669)
(248,388)
(44,508)
(394,565)
(360,369)
Lease liabilities
6.07%
(20,152)
(669)
\u2013
(20,821)
(20,559)
Borrowings
8.85%
(64,190)
(840,085)
\u2013
(904,275)
(748,151)
(529,290)
(1,089,142)
(44,508)
(1,662,940)
(1,472,358)
The following tables set out the details of the Group\u2019s liquidity analysis for its derivative financial instruments based on contractual maturities. The tables have been drawn up based on the undiscounted net cash inflows and outflows on
derivative instruments that settle on a net basis, and the undiscounted gross inflows and outflows on those derivatives that require gross settlement. When the amount payable or receivable is not fixed, the amount disclosed has been
determined by reference to the projected interest rates as illustrated by the yield curves existing at the reporting date.
Within Within
1 year 2 to 5 years Total
At 31 December 2024 $\u2019000 $\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(74,252)
(10,293)
(84,545)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(191,464)
\u2013
(191,464)
Foreign exchange collars \u2013 gross outflows
(191,074)
\u2013
(191,074)
(456,790)
(10,293)
(467,083)
Within Within
1 year 2 to 5 years Total
At 31 December 2023 $\u2019000 $\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(2,290)
\u2013
(2,290)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(113,342)
\u2013
(113,342)
Foreign exchange collars \u2013 gross outflows
(155,071)
\u2013
(155,071)
(270,703)
\u2013
(270,703)
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-489": { "value": "
vi) Capital management
The Group\u2019s objectives when managing capital are to safeguard the Group\u2019s ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure
to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required.
The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates
eroding the Group\u2019s financial results.
", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-490": { "value": "31. Derivative financial instruments The net carrying amount of each category of derivative is set out below:
2024 2023
$\u2019000 $\u2019000
Oil swaps \u2013 cash flow hedge
19,836
9,913
Oil collars \u2013 cash flow hedge
6,536
7,434
Gas swaps \u2013 cash flow hedge
(49,522)
47,232
Gas swaps \u2013 non-cash flow hedge
\u2013
(2,290)
Gas collars \u2013 cash flow hedge
(81,185)
89,944
Interest rate swaps \u2013 non-cash flow hedge
\u2013
637
FX forwards \u2013 cash flow hedge
214
(3,961)
FX forwards \u2013 non-cash flow hedge
(7,484)
\u2013
FX collars \u2013 cash flow hedge
(6,896)
(3,335)
FX collars \u2013 non-cash flow hedge
\u2013
(1,975)
(118,501)
143,599
2024 2023
Maturity analysis of derivative financial instruments $\u2019000 $\u2019000
Non-current assets
\u2013
17,810
Current assets
32,962
139,497
Non-current liabilities
(20,987)
\u2013
Current liabilities
(130,476)
(13,708)
(118,501)
143,599
The fair value of commodity derivatives is estimated using a net present value model (commodity swaps) or an appropriate option valuation model (options and collars). These contracts are valued using observable market pricing data including volatilities. A 20% reduction in future commodity prices, with all other assumptions held constant, would result in a decrease in the fair value of derivatives of $260 million (2023: $113 million). A 20% increase in future commodity prices, with all other assumptions held constant, would result in an increase in the intrinsic value of option derivative instruments at 31 December 2024 of $113 million (2023: $88 million). Derivative financial instruments that are with counterparties included within the RBL are subject to Master Netting Agreements, this includes the majority of the Group\u2019s derivative financial instruments as at 31 December 2024 and 2023. The terms of the Master Netting Arrangements create a legally enforceable right of offset that comes into effect only on the occurrence of a specified event of default or termination event or other events not expected to happen in the normal course of business. Although the Group has the ability to net settle certain transactions with certain counterparties where an election has been made, this is not considered to be significant at 31 December 2024. Accordingly, the Group has not offset any derivatives balances in the statement of financial position in any of the periods presented. Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2024 are detailed below:
Amount recognised in the Related amounts not set off in the
statement of financial position statement of financial position Net amount
$000 $000 $000
Derivative assets
32,962
(22,962)
10,000
Derivative liabilities
(151,463)
22,962
(128,501)
Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2023 are detailed below:
Amount recognised in the Related amounts not set off in the
statement of financial position statement of financial position Net amount
$000 $000 $000
Derivative assets
157,306
(4,436)
152,870
Derivative liabilities
(13,708)
4,436
(9,272)
", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-433": { "value": "
32. Related-party transactions
The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) which owns 52.2% of the issued share capital of Ithaca Energy plc. The registered office address of DKL Energy Limited is 47 Esplanade, St Helier,
JE1 0BD, Jersey.
Following the Business Combination, as set out in note 17, Eni UK Limited, an indirect wholly owned subsidiary of Eni S.p.A., owns 37.2% of the issued share capital of Ithaca Energy plc.
Related party transactions with Eni S.p.A. group from 3 October 2024 were as follows:
Amounts owed by Amounts owed to
Sales to related Purchases from related parties at related parties at
parties related parties 31 December 2024
31 December 2024
1
$000 $000 $000 $000
2024
305,634
2,037
111,639
210,910
1 Includes $204.5 million of deferred consideration in respect of the Business Combination (see note 17 and note 26).
The ultimate parent of the Group is Delek Group Limited (incorporated in Israel), an independent E&P Company listed on the Tel Aviv Stock Exchange. The Group and Delek\u2019s ultimate controlling party is Mr Itshak Sharon Tshuva.
There were no related party transactions with Delek Group Limited or Mr Tshuva in either the year ended 31 December 2024 or the year ended 31 December 2023.
The consolidated financial statements include the financial information of the Group, which comprises the Company and the subsidiaries listed in the following table:
% equity interest at 31 December
Registered office
Country of incorporation
2024
2023
Ithaca Energy (E&P) Limited
1
Jersey
100%
100%
Ithaca Energy (UK) Limited
2
Scotland
100%
100%
Ithaca Minerals (North Sea) Limited
2
Scotland
100%
100%
Ithaca Energy (Holdings) Limited
3
Bermuda
100%
100%
Ithaca Energy Holdings (UK) Limited
2
Scotland
100%
100%
Ithaca Energy (North Sea) PLC
2
Scotland
100%
100%
Ithaca Oil and Gas Limited
4
England and Wales
100%
100%
Ithaca Petroleum Ltd
4
England and Wales
100%
100%
Ithaca Causeway Limited
4
England and Wales
100%
100%
Ithaca Gamma Limited
4
England and Wales
100%
100%
Ithaca Alpha (NI) Limited
5
Northern Ireland
100%
100%
Ithaca Epsilon Limited
4
England and Wales
100%
100%
Ithaca Exploration Limited
4
England and Wales
100%
100%
Ithaca Petroleum EHF
6
Iceland
100%
100%
Ithaca Dorset Limited
4
England and Wales
100%
100%
Ithaca SP UK Limited
4
England and Wales
100%
100%
Ithaca GSA Holdings Limited
1
Jersey
100%
100%
Ithaca GSA Limited
1
Jersey
100%
100%
Ithaca Energy Developments UK Limited
4
England and Wales
100%
100%
FPF-1 Limited
7
Jersey
100%
100%
Ithaca MA Limited
4
England and Wales
100%
100%
Ithaca SP Bonds PLC
4
England and Wales
100%
100%
Ithaca SP Finance Limited
4
England and Wales
100%
100%
Ithaca SP (Holdings) Limited
4
England and Wales
100%
100%
Ithaca SP E&P Limited
4
England and Wales
100%
100%
Ithaca SP O&G Limited
4
England and Wales
100%
100%
Ithaca SPE Limited
4
England and Wales
100%
100%
Ithaca Zeta Limited
4
England and Wales
100%
100%
Ithaca EF Limited (formerly Eni Elgin/Franklin Limited)
4
England and Wales
100%
\u2013
Ithaca UKCS (formerly Eni UKCS Limited)
4
England and Wales
100%
\u2013
Ithaca (NE) E&P Limited (formerly Eni Energy E&P UK Limited)
4
England and Wales
100%
\u2013
Ithaca (NE) UKCS Limited (formerly Eni Energy E&P UKCS Limited)
4
England and Wales
100%
\u2013
Transactions between subsidiaries are eliminated on consolidation.
Foot notes relating to table on preceding page:
1 47 Esplanade, St Helier, Jersey, JE1 0BD
2 13 Queen\u2019s Road, Aberdeen, Scotland AB15 4YL
3 Canon\u2019s Court, 22 Victoria Street, Hamilton HM 12, Bermuda
4 Pinsent Masons LLP, 1 Park Row, Leeds, England, LS1 5AB
5 Pinsent Masons LLP, The Soloist, 1 Lanyon Place, Belfast, BT1 3LP
6 Borgart\u00fani 26, 105 Reykjav\u00edk, Iceland
7 26 New Street, St Helier, Jersey, JE2 3RA
8 All of the above shares represent an ordinary class of shares.
Key management personnel
The following table provides remuneration to key management personnel, being the Executive Directors and members of the Executive Leadership Team, for the periods ended 31 December 2024 and 2023:
2024 2023
Key management personnel $\u2019000 $\u2019000
Salaries and short-term employee benefits
5,910
5,741
Payments made in lieu of pension contributions
288
249
Company pension contributions
148
106
Compensation for loss of office
153
\u2013
Share-based payment
1,575
5,863
8,074
11,959
Further details regarding share-based payments received by key management personnel are set out below.
On 5 January 2024 Alan Bruce stepped down from his role as Chief Executive Officer and on 28 May 2024 Gilad Myerson stepped down from his role as Executive Chairman. Full details of the section 430 (2B) of the Companies
Act 2006 disclosures in respect of Mr Myerson are included in the Remuneration Committee report and full details in respect of Mr Bruce were included in the Directors' remuneration report in the 2023 Annual Report and
Accounts.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-472": { "value": "32. Related-party transactions The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) which owns 52.2% of the issued share capital of Ithaca Energy plc. The registered office address of DKL Energy Limited is 47 Esplanade, St Helier, JE1 0BD, Jersey. Following the Business Combination, as set out in note 17, Eni UK Limited, an indirect wholly owned subsidiary of Eni S.p.A., owns 37.2% of the issued share capital of Ithaca Energy plc. Related party transactions with Eni S.p.A. group from 3 October 2024 were as follows:
Amounts owed by Amounts owed to
Sales to related Purchases from related parties at related parties at
parties related parties 31 December 2024
31 December 2024
1
$000 $000 $000 $000
2024
305,634
2,037
111,639
210,910
1 Includes $204.5 million of deferred consideration in respect of the Business Combination (see note 17 and note 26). The ultimate parent of the Group is Delek Group Limited (incorporated in Israel), an independent E&P Company listed on the Tel Aviv Stock Exchange. The Group and Delek\u2019s ultimate controlling party is Mr Itshak Sharon Tshuva. There were no related party transactions with Delek Group Limited or Mr Tshuva in either the year ended 31 December 2024 or the year ended 31 December 2023.
The consolidated financial statements include the financial information of the Group, which comprises the Company and the subsidiaries listed in the following table:
% equity interest at 31 December
Registered office
Country of incorporation
2024
2023
Ithaca Energy (E&P) Limited
1
Jersey
100%
100%
Ithaca Energy (UK) Limited
2
Scotland
100%
100%
Ithaca Minerals (North Sea) Limited
2
Scotland
100%
100%
Ithaca Energy (Holdings) Limited
3
Bermuda
100%
100%
Ithaca Energy Holdings (UK) Limited
2
Scotland
100%
100%
Ithaca Energy (North Sea) PLC
2
Scotland
100%
100%
Ithaca Oil and Gas Limited
4
England and Wales
100%
100%
Ithaca Petroleum Ltd
4
England and Wales
100%
100%
Ithaca Causeway Limited
4
England and Wales
100%
100%
Ithaca Gamma Limited
4
England and Wales
100%
100%
Ithaca Alpha (NI) Limited
5
Northern Ireland
100%
100%
Ithaca Epsilon Limited
4
England and Wales
100%
100%
Ithaca Exploration Limited
4
England and Wales
100%
100%
Ithaca Petroleum EHF
6
Iceland
100%
100%
Ithaca Dorset Limited
4
England and Wales
100%
100%
Ithaca SP UK Limited
4
England and Wales
100%
100%
Ithaca GSA Holdings Limited
1
Jersey
100%
100%
Ithaca GSA Limited
1
Jersey
100%
100%
Ithaca Energy Developments UK Limited
4
England and Wales
100%
100%
FPF-1 Limited
7
Jersey
100%
100%
Ithaca MA Limited
4
England and Wales
100%
100%
Ithaca SP Bonds PLC
4
England and Wales
100%
100%
Ithaca SP Finance Limited
4
England and Wales
100%
100%
Ithaca SP (Holdings) Limited
4
England and Wales
100%
100%
Ithaca SP E&P Limited
4
England and Wales
100%
100%
Ithaca SP O&G Limited
4
England and Wales
100%
100%
Ithaca SPE Limited
4
England and Wales
100%
100%
Ithaca Zeta Limited
4
England and Wales
100%
100%
Ithaca EF Limited (formerly Eni Elgin/Franklin Limited)
4
England and Wales
100%
\u2013
Ithaca UKCS (formerly Eni UKCS Limited)
4
England and Wales
100%
\u2013
Ithaca (NE) E&P Limited (formerly Eni Energy E&P UK Limited)
4
England and Wales
100%
\u2013
Ithaca (NE) UKCS Limited (formerly Eni Energy E&P UKCS Limited)
4
England and Wales
100%
\u2013
Transactions between subsidiaries are eliminated on consolidation. Foot notes relating to table on preceding page: 1 47 Esplanade, St Helier, Jersey, JE1 0BD 2 13 Queen\u2019s Road, Aberdeen, Scotland AB15 4YL 3 Canon\u2019s Court, 22 Victoria Street, Hamilton HM 12, Bermuda 4 Pinsent Masons LLP, 1 Park Row, Leeds, England, LS1 5AB 5 Pinsent Masons LLP, The Soloist, 1 Lanyon Place, Belfast, BT1 3LP 6 Borgart\u00fani 26, 105 Reykjav\u00edk, Iceland 7 26 New Street, St Helier, Jersey, JE2 3RA 8 All of the above shares represent an ordinary class of shares. Key management personnel The following table provides remuneration to key management personnel, being the Executive Directors and members of the Executive Leadership Team, for the periods ended 31 December 2024 and 2023:
2024 2023
Key management personnel $\u2019000 $\u2019000
Salaries and short-term employee benefits
5,910
5,741
Payments made in lieu of pension contributions
288
249
Company pension contributions
148
106
Compensation for loss of office
153
\u2013
Share-based payment
1,575
5,863
8,074
11,959
Further details regarding share-based payments received by key management personnel are set out below. On 5 January 2024 Alan Bruce stepped down from his role as Chief Executive Officer and on 28 May 2024 Gilad Myerson stepped down from his role as Executive Chairman. Full details of the section 430 (2B) of the Companies Act 2006 disclosures in respect of Mr Myerson are included in the Remuneration Committee report and full details in respect of Mr Bruce were included in the Directors' remuneration report in the 2023 Annual Report and Accounts.", "dimensions": { "concept": "ifrs-full:DisclosureOfTransactionsBetweenRelatedPartiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-15": { "value": "DKL Energy Limited", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-14": { "value": "Delek Group Limited", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-500": { "value": "The consolidated financial statements include the financial information of the Group, which comprises the Company and the subsidiaries listed in the following table:
% equity interest at 31 December
Registered office
Country of incorporation
2024
2023
Ithaca Energy (E&P) Limited
1
Jersey
100%
100%
Ithaca Energy (UK) Limited
2
Scotland
100%
100%
Ithaca Minerals (North Sea) Limited
2
Scotland
100%
100%
Ithaca Energy (Holdings) Limited
3
Bermuda
100%
100%
Ithaca Energy Holdings (UK) Limited
2
Scotland
100%
100%
Ithaca Energy (North Sea) PLC
2
Scotland
100%
100%
Ithaca Oil and Gas Limited
4
England and Wales
100%
100%
Ithaca Petroleum Ltd
4
England and Wales
100%
100%
Ithaca Causeway Limited
4
England and Wales
100%
100%
Ithaca Gamma Limited
4
England and Wales
100%
100%
Ithaca Alpha (NI) Limited
5
Northern Ireland
100%
100%
Ithaca Epsilon Limited
4
England and Wales
100%
100%
Ithaca Exploration Limited
4
England and Wales
100%
100%
Ithaca Petroleum EHF
6
Iceland
100%
100%
Ithaca Dorset Limited
4
England and Wales
100%
100%
Ithaca SP UK Limited
4
England and Wales
100%
100%
Ithaca GSA Holdings Limited
1
Jersey
100%
100%
Ithaca GSA Limited
1
Jersey
100%
100%
Ithaca Energy Developments UK Limited
4
England and Wales
100%
100%
FPF-1 Limited
7
Jersey
100%
100%
Ithaca MA Limited
4
England and Wales
100%
100%
Ithaca SP Bonds PLC
4
England and Wales
100%
100%
Ithaca SP Finance Limited
4
England and Wales
100%
100%
Ithaca SP (Holdings) Limited
4
England and Wales
100%
100%
Ithaca SP E&P Limited
4
England and Wales
100%
100%
Ithaca SP O&G Limited
4
England and Wales
100%
100%
Ithaca SPE Limited
4
England and Wales
100%
100%
Ithaca Zeta Limited
4
England and Wales
100%
100%
Ithaca EF Limited (formerly Eni Elgin/Franklin Limited)
4
England and Wales
100%
\u2013
Ithaca UKCS (formerly Eni UKCS Limited)
4
England and Wales
100%
\u2013
Ithaca (NE) E&P Limited (formerly Eni Energy E&P UK Limited)
4
England and Wales
100%
\u2013
Ithaca (NE) UKCS Limited (formerly Eni Energy E&P UKCS Limited)
4
England and Wales
100%
\u2013
Transactions between subsidiaries are eliminated on consolidation. Foot notes relating to table on preceding page: 1 47 Esplanade, St Helier, Jersey, JE1 0BD 2 13 Queen\u2019s Road, Aberdeen, Scotland AB15 4YL 3 Canon\u2019s Court, 22 Victoria Street, Hamilton HM 12, Bermuda 4 Pinsent Masons LLP, 1 Park Row, Leeds, England, LS1 5AB 5 Pinsent Masons LLP, The Soloist, 1 Lanyon Place, Belfast, BT1 3LP 6 Borgart\u00fani 26, 105 Reykjav\u00edk, Iceland 7 26 New Street, St Helier, Jersey, JE2 3RA 8 All of the above shares represent an ordinary class of shares. ", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-491": { "value": "Key management personnel The following table provides remuneration to key management personnel, being the Executive Directors and members of the Executive Leadership Team, for the periods ended 31 December 2024 and 2023:
2024 2023
Key management personnel $\u2019000 $\u2019000
Salaries and short-term employee benefits
5,910
5,741
Payments made in lieu of pension contributions
288
249
Company pension contributions
148
106
Compensation for loss of office
153
\u2013
Share-based payment
1,575
5,863
8,074
11,959
Further details regarding share-based payments received by key management personnel are set out below. On 5 January 2024 Alan Bruce stepped down from his role as Chief Executive Officer and on 28 May 2024 Gilad Myerson stepped down from his role as Executive Chairman. Full details of the section 430 (2B) of the Companies Act 2006 disclosures in respect of Mr Myerson are included in the Remuneration Committee report and full details in respect of Mr Bruce were included in the Directors' remuneration report in the 2023 Annual Report and Accounts.", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-434": { "value": "
33. Share-based payments
The charge for share-based payment transactions in the year to 31 December 2024 was $6.1 million (2023: $16.4 million). Like other elements of compensation, this charge is processed through the time-writing system which allocates
costs, based on time spent by individuals, to various activities within the Ithaca Energy plc Group. Part of this cost is, therefore, capitalised as directly attributable to capital projects and part is charged to the statement of profit or loss as
operating costs of hydrocarbon activities, pre-licence exploration costs or administrative expenses.
Long-Term Incentive Plans (LTIPs), Restricted Stock Units (RSUs) and Deferred Bonus Shares (DBSs)
Outstanding share options under LTIPs and DBS were as follows:
Heritage awards
At-IPO awards
2022
LTIP awards
2024
LTIP awards
2024
RSU awards
2024
DBS awards
Total
Balance at 1 January 2023
1,687,296
4,908,903
2,836,660
\u2013
\u2013
\u2013
9,432,859
Awarded during the year in lieu of dividend payments
191,401
190,426
\u2013
\u2013
\u2013
\u2013
381,827
Forfeited during the year
(127,880)
(296,966)
(276,123)
\u2013
\u2013
\u2013
(700,969)
Exercised during the year
(921,882)
(521,679)
\u2013
\u2013
\u2013
\u2013
(1,443,561)
Balance at 31 December 2023
828,935
4,280,684
2,560,537
\u2013
\u2013
\u2013
7,670,156
Granted during the year
\u2013
\u2013
\u2013
3,589,590
303,103
239,291
4,131,984
Awarded during the year in lieu of dividend payments
76,000
1,454,497
\u2013
532,474
51,211
40,430
2,154,612
Forfeited during the year
\u2013
(293,867)
(249,919)
\u2013
\u2013
\u2013
(543,786)
Exercised during the year
(885,959)
(974,153)
\u2013
\u2013
\u2013
\u2013
(1,860,112)
Balance at 31 December 2024
18,976
4,467,161
2,310,618
4,122,064
354,314
279,721
11,552,854
Exercisable at 31 December 2024
18,976
2,478,094
\u2013
\u2013
\u2013
\u2013
2,497,070
Share option exercise price
\u00a3nil
\u00a3nil
\u00a3nil
\u00a3nil
\u00a3nil
\u00a3nil
N/A
Weighted average share price on date of exercise
\u00a31.20
\u00a31.15
N/A
N/A
N/A
N/A
N/A
Weighted average remaining life
N/A
0.9 years
1.3 years
2.6 years
2.5 years
2.5 years
N/A
All LTIP, DBS and RSU awards are nil-cost options. There are no performance conditions attaching to the Heritage, At-IPO, 2024 DBS or 2024 RSU awards. Details of the performance conditions of the 2022 LTIP and the 2024
LTIP are set out in the Remuneration Committee report. The fair values of all the LTIP awards were determined based on the share price on date of award. The Heritage awards vested over the period to 14 November 2023, the At-IPO
awards vest in three equal tranches over the period to 14 November 2025, the 2022 LTIP awards vest over the period to 1 April 2026, the 2024 LTIP awards vest over the periods to 4 July 2027 and 11 October 2027, the 2024 DBS
awards vest over the period to 5 July 2027 and the 2024 RSU awards vest in three equal tranches over the period to 4 July 2027. It is anticipated that future exercises of LTIP, DBS and RSU awards will be settled by equity.
The total charge for LTIP share options, DBS awards and RSU awards in the year to 31 December 2024 was $6.1 million (2023: $12.9 million).
IPO-related share options
Under the terms of their termination agreements, both Mr Myerson and Mr Bruce retained an entitlement to $2.0 million worth of share options each. The IPO-related share options were fully expensed in the period up to
31 December 2023 and the charge for the year to 31 December 2024 was $nil (2023: $0.5 million).
Management Equity Plan (MEP)
During the year to 31 December 2023, Mr Myerson elected to receive the Aggregate Guaranteed Payment (AGP) and $8.0 million (AGP of $10.0 million less special bonuses of $2.0 million) was paid to him on 1 December 2023.
As a result, the MEP share options, which would otherwise have vested over the period to 30 September 2026, were transferred back to the Company for nil payment.
There were no performance conditions attaching to either the MEP share options or the AGP.
The total share-based payment charge for MEP arrangements in the year to 31 December 2024 was $nil (2023: $3.0 million).
The share-based payment reserve of $18.8 million (2023: $15.5 million) reflects the opening balance of $15.5 million (2023: $4.9 million) plus the charge of $6.1 million (2023: $12.9 million) for LTIPs and DBSs plus the charge of $nil
(2023: $0.5 million) for IPO-related share options less the cost of satisfying exercises during the year of $2.8 million (2023: $2.8 million).
", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-435": { "value": "
34. Dividends
2024 2023
$m $m
First 2024 interim dividend of $0.0986 (2023: $0.132) per ordinary share announced 22 August 2024 and paid 27 September 2024
99.4
133.0
Second 2024 dividend of $0.1209 (2023: $0.132) per ordinary share announced 21 November 2024 and paid 20 December 2024
199.7
133.0
Total dividends paid relating to the year ended 31 December
1
299.1
266.0
Third 2024 interim dividend of $0.1209 (2023: $0.132) per ordinary share announced 26 March 2025 and payable 25 April 2025 (not accrued in the 2024 results)
1
200.0
133.6
Total dividends paid or payable relating to year ended 31 December
499.1
399.6
1. The third 2023 interim dividend of $133.6 million was paid on 17 April 2024. Total cash payments in the year to 31 December 2024 were $432.7 million.
", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } }, "fact-436": { "value": "
35. Subsequent events
On 29 January 2025, the Group announced a reorganisation and streamlining of the organisational structure for onshore staff with a targeted completion of 1 July 2025. It is not anticipated that the cost of this reorganisation
will be material.
On 30 January 2025, the Court of Session ruled that consent had been unlawfully given in relation to the sanctioning of the Rosebank field development and that a new consent application would be required which included scope 3
emissions. It did, however, permit the project to progress as planned whilst this new consent is sought but that no oil could be extracted until consent has been given. Further details are set out in note 3.
On 25 March 2025, the Group announced the signing of a sale and purchase agreement to acquire the entire issued share capital of JAPEX UK E&P Limited for an enterprise value of $193 million, based on an effective date of
1 January 2024. The acquisition, which is subject to certain conditions including regulatory approval, and is subject to customary purchase price adjustments, which, assuming an illustrative completion date of 30 June 2025, equates
to an estimated payment at completion of approximately $140 million.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2024-01-01T00:00:00/2025-01-01T00:00:00" } } } }