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1. General information
Ithaca Energy plc (the Group or Ithaca Energy), is a 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, United Kingdom, W1G 0PP.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-2": { "value": "Ithaca Energy plc", "dimensions": { "concept": "ifrs-full:NameOfReportingEntityOrOtherMeansOfIdentification", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-3": { "value": " Company limited by shares", "dimensions": { "concept": "ifrs-full:LegalFormOfEntity", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-4": { "value": "UK", "dimensions": { "concept": "ifrs-full:CountryOfIncorporation", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-385": { "value": "UK", "dimensions": { "concept": "ifrs-full:DomicileOfEntity", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-5": { "value": " development and production of oil and gas in the North Sea. ", "dimensions": { "concept": "ifrs-full:DescriptionOfNatureOfEntitysOperationsAndPrincipalActivities", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-6": { "value": "33 Cavendish Square, London, United Kingdom, W1G 0PP", "dimensions": { "concept": "ifrs-full:AddressOfRegisteredOfficeOfEntity", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-388": { "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 (US$\u2019000), except when otherwise indicated. The principal accounting policies applied in the preparation of the financial statements are set out below. These policies have been consistently applied to all the periods presented.", "dimensions": { "concept": "ifrs-full:DisclosureOfBasisOfPreparationOfFinancialStatementsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-442": { "value": "The consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standards (IAS) and in conformity with the requirements of the Companies Act 2006.", "dimensions": { "concept": "ifrs-full:StatementOfIFRSCompliance", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-443": { "value": "
The consolidated financial statements are presented in US Dollars as this is the functional currency of the business. All values are rounded to the nearest thousand (US$\u2019000), except when otherwise indicated.
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForFunctionalCurrencyExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-386": { "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/annual 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 New unsecured loan arrangement of $100 million with bp which was fully drawn at 31 December 2023 and a new $150 million optional project specific capital expenditure carry arrangement available at the discretion of the Group
which was undrawn at 31 December 2023;
\u2022 Reserves Based Lending (RBL) liquidity headroom of $836 million ($nil drawn versus $836 million available), plus $303 million of cash as at 22 March 2024; and
\u2022 Robust operational performance and a well-diversified portfolio.
Cash flow forecast \u2013 base case assumptions: 2024
H1 2025
Average oil price
$/bbl
81
77
Average gas price
p/th
67
75
Average hedged oil price (including floor price for zero cost collars)
$/bbl
78
N/A
Average hedged gas price (including floor price for zero cost collars)
p/th
137
123
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, after
consideration of mitigation strategies within management\u2019s control, there were 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 test 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. In addition to this, there is also further potential to refinance the Group\u2019s borrowing arrangements. The analysis demonstrated
that the Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 June 2025 to continue trading.
Based on their assessment of the Group\u2019s financial position in the period to 30 June 2025, 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 and all wholly-owned subsidiaries as listed per note 31. 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, and the eventual cessation of production of mature fields which have higher carbon intensity. 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 \u2018key sources of estimation uncertainty\u2019 as required by IAS 1 (being those which could have a material impact on the Group\u2019s results in the
12 months following the reporting date) 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 real terms from 2028, $93/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 of \u00a370 per tonne for CO
2
e. 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 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 46, 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. The recoverability of the existing intangibles was considered during 2023, 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 $69 million (2022: $74 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 an acquisition 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 acquisition. 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 acquisition date. The excess of the cost of acquisition over the fair value of the Group\u2019s share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition 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 and associates 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. Associates are investments over which the Group has significant influence but not control or joint control, and generally holds between 20% and 50% of the voting rights. The Group\u2019s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation and its expenses (including its 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 recognized 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, trans actions 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).
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 Group derecognises financial liabilities when, and only when, the Group\u2019s obligations are discharged, cancelled or have expired. The difference between the carrying amount of the financial asset or financial liability
derecognised and the consideration received/receivable or paid/payable respectively 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 as they have a business
model of held to collect and the terms of the financial instrument meet the 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.
Interest-free loans from parents are initially recognised at fair value. The difference between the fair value of the loans and the nominal value is accounted for as a capital contribution and is credited to equity. After initial recognition,
the loans are measured at amortised cost using implied interest rate of the notes.
Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability and original issue discounts on long-term debt 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.
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 29 and 30.
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 hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive
income and accumulated in the 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 \u2018other gains and losses\u2019 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 29 and note 30 set out details of the fair values of the derivative instruments used for hedging purposes and movements in the hedging reserve in equity are detailed in note 29.
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 \u2018measurement period\u2019
(which cannot exceed one year from the acquisition date) about facts and circumstances that existed at the acquisition date.
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 judgment 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 flow, 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, and \u2018overlift\u2019 is included within trade and other payables in the statement of financial position. Both are stated at
net realisable value. 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 \u2013
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 or previously impaired assets (excluding goodwill)
where a reversal of a previous impairment may arise. 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. 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 reverse, based on the laws that have been enacted or substantively enacted at each balance sheet date. 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.
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 material impairment charges or reversals, non-cash bargain purchase credits, the tax effect of these items
where applicable and non-cash deferred tax charges on the initial application 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 221 to 223.
C hanges in accounting pronouncements The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2022 to 31 December 2023 including IFRS 17 Insurance Contracts. There was no impact of this or of any of the amendments to existing standards and interpretations which were effective from 1 January 2023. New and revised IFRS Standards in issue but not yet effective At the date of authorisation of these consolidated financial statements, the Group has not applied the following revisions to IFRS Standards that have been issued but are not yet effective. Amendments to IFRS 10 and IAS 28 Sale or Contribution of Assets between an Investor and its Associate or Joint Venture Amendments to IAS 1 Classification of Liabilities as Current or Non-current Amendments to IAS 1 Non-current liabilities with Covenants Amendments to IAS 7 and IFRS 7 Supplier Finance Arrangements Amendments to IFRS 16 Lease Liability in a Sale and Leaseback Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability The Company does not expect that the adoption of the amendments listed above will have a material impact on the consolidated financial statements of the Group in future periods. 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. 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. A nominal discount rate of 4.60% (2022: 4.25%), based on the average risk-free rate over the second half of 2023, is used to discount the estimated costs. The inflation rate applied to estimated costs is 2.0% (2022: 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 $223 million or $188 million respectively (2022: $218 million or $201 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.
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 probability of payment, with all other assumptions held constant, would result in a decrease in contingent consideration of $97.1 million (2022: $87.1 million). Whereas a 20% increase in probability of payment,
with all other assumptions held constant, would result in an increase in contingent consideration of $84.1 million (2022: $83.6 million).
Other areas of estimation
The key assumptions concerning the future, and other sources of estimation uncertainty at the reporting period, but are not expected to cause a material adjustment to the carrying amounts of assets and liabilities within the next
financial year, are discussed below:
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%, 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 27.
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 2023, 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 $304 million (2022: $24 million). It should be noted that mitigating actions
are considered to be available to materially offset this impact. An increase in future revenues would result in no additional deferred tax asset recognition on the basis that deferred tax assets are already recognised in full. The $304 million
(2022: $24 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.
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 critical 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 material
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
internal 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 supported 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.
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 field carrying value
Management has reviewed the carrying value of the Cambo field of $391 million and has concluded that due to the recent 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 progress the project towards FID and assist in obtaining the additional
funding required for the project. The Group is also mindful that the outcome of the 2024 General Election could have implications for the project as well as the wider fiscal uncertainties on oil and gas investment in general. Details of
contingent consideration in respect of Cambo are set out in note 17 and note 25.
", "dimensions": { "concept": "ifrs-full:DisclosureOfMaterialAccountingPolicyInformationExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-390": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-389": { "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/annual 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 New unsecured loan arrangement of $100 million with bp which was fully drawn at 31 December 2023 and a new $150 million optional project specific capital expenditure carry arrangement available at the discretion of the Group which was undrawn at 31 December 2023; \u2022 Reserves Based Lending (RBL) liquidity headroom of $836 million ($nil drawn versus $836 million available), plus $303 million of cash as at 22 March 2024; and \u2022 Robust operational performance and a well-diversified portfolio.
Cash flow forecast \u2013 base case assumptions: 2024
H1 2025
Average oil price
$/bbl
81
77
Average gas price
p/th
67
75
Average hedged oil price (including floor price for zero cost collars)
$/bbl
78
N/A
Average hedged gas price (including floor price for zero cost collars)
p/th
137
123
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, after consideration of mitigation strategies within management\u2019s control, there were 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 test 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. In addition to this, there is also further potential to refinance the Group\u2019s borrowing arrangements. The analysis demonstrated that the Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 June 2025 to continue trading. Based on their assessment of the Group\u2019s financial position in the period to 30 June 2025, 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-391": { "value": "Basis of consolidation The consolidated financial statements of the Group includes the financial information of Ithaca Energy and all wholly-owned subsidiaries as listed per note 31. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-444": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-392": { "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 CO2 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, and the eventual cessation of production of mature fields which have higher carbon intensity. 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 \u2018key sources of estimation uncertainty\u2019 as required by IAS 1 (being those which could have a material impact on the Group\u2019s results in the 12 months following the reporting date) 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 real terms from 2028, $93/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 of \u00a370 per tonne for CO2 e. 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 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 46, 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. The recoverability of the existing intangibles was considered during 2023, 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 $69 million (2022: $74 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-445": { "value": "
Business combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the consideration given for the assets acquired, equity instruments issued and liabilities incurred or
assumed at the date of completion of the acquisition. 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 acquisition date. The excess of the cost of acquisition over the fair value of the Group\u2019s share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-393": { "value": "Business combinations Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the consideration given for the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. 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 acquisition date. The excess of the cost of acquisition over the fair value of the Group\u2019s share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-446": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-470": { "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 or previously impaired assets (excluding goodwill) where a reversal of a previous impairment may arise. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-497": { "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 or previously impaired assets (excluding goodwill) where a reversal of a previous impairment may arise. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-394": { "value": "
Interest in joint ventures and associates
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. Associates are investments over which the Group has significant influence but not control or joint control, and
generally holds between 20% and 50% of the voting rights.
The Group\u2019s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly),
its revenue from the sale of its share of the output arising from the joint operation and its expenses (including its share of any expenses incurred jointly).
", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociatesAndJointVenturesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-471": { "value": "Interest in joint ventures and associates 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. Associates are investments over which the Group has significant influence but not control or joint control, and generally holds between 20% and 50% of the voting rights. The Group\u2019s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation and its expenses (including its share of any expenses incurred jointly). ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentInAssociates", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-447": { "value": "Interest in joint ventures and associates 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. Associates are investments over which the Group has significant influence but not control or joint control, and generally holds between 20% and 50% of the voting rights. The Group\u2019s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation and its expenses (including its share of any expenses incurred jointly). ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForInvestmentsInJointVentures", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-395": { "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 recognized 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-396": { "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, trans actions 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-397": { "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 Group derecognises financial liabilities when, and only when, the Group\u2019s obligations are discharged, cancelled or have expired. The difference between the carrying amount of the financial asset or financial liability derecognised and the consideration received/receivable or paid/payable respectively 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 as they have a business model of held to collect and the terms of the financial instrument meet the 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. Interest-free loans from parents are initially recognised at fair value. The difference between the fair value of the loans and the nominal value is accounted for as a capital contribution and is credited to equity. After initial recognition, the loans are measured at amortised cost using implied interest rate of the notes. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability and original issue discounts on long-term debt 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. 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 29 and 30. 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 hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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 \u2018other gains and losses\u2019 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 29 and note 30 set out details of the fair values of the derivative instruments used for hedging purposes and movements in the hedging reserve in equity are detailed in note 29. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-490": { "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 29 and 30. 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 hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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 \u2018other gains and losses\u2019 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 29 and note 30 set out details of the fair values of the derivative instruments used for hedging purposes and movements in the hedging reserve in equity are detailed in note 29. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-448": { "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 29 and 30. 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 hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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 \u2018other gains and losses\u2019 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 29 and note 30 set out details of the fair values of the derivative instruments used for hedging purposes and movements in the hedging reserve in equity are detailed in note 29. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-472": { "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 hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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 \u2018other gains and losses\u2019 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 29 and note 30 set out details of the fair values of the derivative instruments used for hedging purposes and movements in the hedging reserve in equity are detailed in note 29. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-398": { "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 \u2018measurement period\u2019 (which cannot exceed one year from the acquisition date) about facts and circumstances that existed at the acquisition date. 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 judgment 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-399": { "value": "Cash and cash equivalents For the purpose of the statement of cash flow, 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-400": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-401": { "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, and \u2018overlift\u2019 is included within trade and other payables in the statement of financial position. Both are stated at net realisable value. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-402": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-403": { "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 \u2013 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-449": { "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 \u2013 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-473": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-474": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-450": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-404": { "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. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-405": { "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 reverse, based on the laws that have been enacted or substantively enacted at each balance sheet date. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-451": { "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 reverse, based on the laws that have been enacted or substantively enacted at each balance sheet date. 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-406": { "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. ", "dimensions": { "concept": "ifrs-full:DescriptionOfAccountingPolicyForLeasesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-407": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-408": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-409": { "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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-410": { "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 material impairment charges or reversals, non-cash bargain purchase credits, the tax effect of these items where applicable and non-cash deferred tax charges on the initial application 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 221 to 223. ", "dimensions": { "concept": "ifrs-full:DisclosureOfComparativeInformationPreparedUnderPreviousGAAPExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-411": { "value": "hanges in accounting pronouncements The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2022 to 31 December 2023 including IFRS 17 Insurance Contracts. There was no impact of this or of any of the amendments to existing standards and interpretations which were effective from 1 January 2023. New and revised IFRS Standards in issue but not yet effective At the date of authorisation of these consolidated financial statements, the Group has not applied the following revisions to IFRS Standards that have been issued but are not yet effective. Amendments to IFRS 10 and IAS 28 Sale or Contribution of Assets between an Investor and its Associate or Joint Venture Amendments to IAS 1 Classification of Liabilities as Current or Non-current Amendments to IAS 1 Non-current liabilities with Covenants Amendments to IAS 7 and IFRS 7 Supplier Finance Arrangements Amendments to IFRS 16 Lease Liability in a Sale and Leaseback Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability The Company does not expect that the adoption of the amendments listed above will have a material impact on the consolidated financial statements of the Group in future periods. ", "dimensions": { "concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-452": { "value": "
New and revised IFRS Standards in issue but not yet effective
At the date of authorisation of these consolidated financial statements, the Group has not applied the following revisions to IFRS Standards that have been issued but are not yet effective.
Amendments to IFRS 10 and IAS 28 Sale or Contribution of Assets between an Investor and its Associate or Joint Venture
Amendments to IAS 1 Classification of Liabilities as Current or Non-current
Amendments to IAS 1 Non-current liabilities with Covenants
Amendments to IAS 7 and IFRS 7 Supplier Finance Arrangements
Amendments to IFRS 16 Lease Liability in a Sale and Leaseback
Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability
The Company does not expect that the adoption of the amendments listed above will have a material impact on the consolidated financial statements of the Group in future periods.
", "dimensions": { "concept": "ifrs-full:DescriptionOfExpectedImpactOfInitialApplicationOfNewStandardsOrInterpretations", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-412": { "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.
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. A nominal discount rate of 4.60% (2022: 4.25%),
based on the average risk-free rate over the second half of 2023, is used to discount the estimated costs. The inflation rate applied to estimated costs is 2.0% (2022: 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 $223 million or $188 million respectively (2022: $218 million or $201 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.
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 probability of payment, with all other assumptions held constant, would result in a decrease in contingent consideration of $97.1 million (2022: $87.1 million). Whereas a 20% increase in probability of payment, with all other assumptions held constant, would result in an increase in contingent consideration of $84.1 million (2022: $83.6 million). Other areas of estimation The key assumptions concerning the future, and other sources of estimation uncertainty at the reporting period, but are not expected to cause a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below: 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%, 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 27. 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 2023, 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 $304 million (2022: $24 million). It should be noted that mitigating actions are considered to be available to materially offset this impact. An increase in future revenues would result in no additional deferred tax asset recognition on the basis that deferred tax assets are already recognised in full. The $304 million (2022: $24 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. 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 critical 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 material 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 internal 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 supported 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. 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 field carrying value Management has reviewed the carrying value of the Cambo field of $391 million and has concluded that due to the recent licence extension to 31 March 2026 and the detailed plans in place for final investment decision (FID), there are currently no indicators of impairment. The Group is actively engaging with potential farm-in partners to secure an aligned joint venture partnership that would progress the project towards FID and assist in obtaining the additional funding required for the project. The Group is also mindful that the outcome of the 2024 General Election could have implications for the project as well as the wider fiscal uncertainties on oil and gas investment in general. Details of contingent consideration in respect of Cambo are set out in note 17 and note 25.", "dimensions": { "concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-413": { "value": "
4. Segmental reporting
The Group operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area, presently being the North Sea. The Group\u2019s segmental reporting structure
remained in place for all periods presented and is consistent with the way in which the Group\u2019s activities are reported to the Board and Chief Decision Making Officer. The Group\u2019s activities are considered to be an individual operating
segment due to the nature of the Group\u2019s operations being consistent, and such operations existing in a single geographical region that is covered by the same regulations.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEntitysReportableSegmentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-414": { "value": "
5. Revenue
2023 2022
US$\u2019000 US$\u2019000
Oil sales
1,329,751
1,692,697
Gas sales
658,659
1,348,212
Condensate sales
48,789
75,445
Other income
32,341
40,617
Realised losses on oil derivative contracts
(31,676)
(211,636)
Put premiums on oil derivative instruments
(11,850)
(14,629)
Realised gains/(losses) on gas derivative contracts
297,387
(289,877)
Put premiums on gas derivative instruments
(3,590)
(42,347)
2,319,811
2,598,482
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 transactions price 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 2023, representing $1,296 million and $436 million of revenue respectively
(2022: one customer representing $2,436 million of revenue).
Revenue from contracts with customers derives largely from customers within a single geographical region, being the United Kingdom. Revenue from contracts with customers out with the United Kingdom is immaterial and is therefore
not disclosed separately.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-453": { "value": "5. Revenue
2023 2022
US$\u2019000 US$\u2019000
Oil sales
1,329,751
1,692,697
Gas sales
658,659
1,348,212
Condensate sales
48,789
75,445
Other income
32,341
40,617
Realised losses on oil derivative contracts
(31,676)
(211,636)
Put premiums on oil derivative instruments
(11,850)
(14,629)
Realised gains/(losses) on gas derivative contracts
297,387
(289,877)
Put premiums on gas derivative instruments
(3,590)
(42,347)
2,319,811
2,598,482
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 transactions price 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 2023, representing $1,296 million and $436 million of revenue respectively (2022: one customer representing $2,436 million of revenue). Revenue from contracts with customers derives largely from customers within a single geographical region, being the United Kingdom. Revenue from contracts with customers out with the United Kingdom is immaterial and is therefore not disclosed separately.", "dimensions": { "concept": "ifrs-full:DisclosureOfRevenueFromContractsWithCustomersExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-475": { "value": "Revenue from two customers exceeded 10% of the Group\u2019s consolidated revenue arising from hydrocarbon sales for the year ended 31 December 2023, representing $1,296 million and $436 million of revenue respectively (2022: one customer representing $2,436 million of revenue). ", "dimensions": { "concept": "ifrs-full:DisclosureOfSegmentsMajorCustomersExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-415": { "value": "
6. Cost of sales
2023 2022
US$\u2019000 US$\u2019000
Movement in oil and gas inventory (including underlift/overlift)
20,582
(130,295)
Operating costs of hydrocarbon activities
(576,660)
(547,795)
Materials inventory provision
(16,268)
\u2013
Royalties
(4,364)
(11,287)
Depreciation on right-of-use assets (note 15)
(42,648)
(37,43
8)
Depletion, depreciation and amortisation (note 15)
(697,652)
(625,509)
(1,317,010)
(1,352,324)
Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds a 100% interest in the Stella and Harrier fields.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-476": { "value": "6. Cost of sales
2023 2022
US$\u2019000 US$\u2019000
Movement in oil and gas inventory (including underlift/overlift)
20,582
(130,295)
Operating costs of hydrocarbon activities
(576,660)
(547,795)
Materials inventory provision
(16,268)
\u2013
Royalties
(4,364)
(11,287)
Depreciation on right-of-use assets (note 15)
(42,648)
(37,43
8)
Depletion, depreciation and amortisation (note 15)
(697,652)
(625,509)
(1,317,010)
(1,352,324)
Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds a 100% interest in the Stella and Harrier fields. 7. Administrative expenses
2023 2022
US$\u2019000 US$\u2019000
Administrative expenses excluding transaction costs
(34,259)
(41,762)
Transaction costs
\u2013
(46,089)
(34,259)
(87,8 51)
Transactions costs in 2022 relate to the acquisitions of Marubeni Oil & Gas Limited (MOGL), Summit Exploration and Production Limited (Summit) and Siccar Point Energy entities, and costs incurred in connection to the IPO. Further details on the acquisitions can be found in note 17. The total employee benefit expenses which are either capitalised or included in cost of sales, pre-licence exploration and evaluation expenses and administrative expenses are noted below. Employee benefit expenses
2023 2022
US$\u2019000 US$\u2019000
Wages and salaries
(104,027)
(81,017)
Share-based payment charges (note 32)
(16,369)
(14,069)
Social security costs
(12,290)
(9,902)
Pension costs
(9,997)
(8,298)
(142,683)
(113,286)
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 Directors\u2019 remuneration report on pages 112 to 136. Directors\u2019 emoluments in aggregate were $13.4 million (2022: $18.1 million). The average number of employees during each year was as follows:
2023
2022
Onshore and administrative
316
268
Offshore
283
249
599
517
The increase in average employee numbers in 2023 reflects the full-year impact of acquisitions made in 2022 and the conversion of a number of contractor roles to staff positions. Audit fees
2023 2022
US$\u2019000 US$\u2019000
Fees payable to the Company\u2019s auditor for audit of the Company\u2019s financial statements
1,286
1,095
Audit of the Company\u2019s subsidiaries pursuant to legislation
326
324
Non-audit fees provided by the auditors
205
4,707
1,817
6,126
Non-audit fees provided by the auditors for the year ended 31 December 2023 comprise audit-related assurance services of $205k (2022: $170k), other assurance services of $nil (2022: $990k) and other non-audit services of $nil (2022: $3,547k), with the latter two captions in 2022 relating to reporting accountant workstreams in relation to the IPO.", "dimensions": { "concept": "ifrs-full:DisclosureOfExpensesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-454": { "value": "6. Cost of sales
2023 2022
US$\u2019000 US$\u2019000
Movement in oil and gas inventory (including underlift/overlift)
20,582
(130,295)
Operating costs of hydrocarbon activities
(576,660)
(547,795)
Materials inventory provision
(16,268)
\u2013
Royalties
(4,364)
(11,287)
Depreciation on right-of-use assets (note 15)
(42,648)
(37,43
8)
Depletion, depreciation and amortisation (note 15)
(697,652)
(625,509)
(1,317,010)
(1,352,324)
Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds a 100% interest in the Stella and Harrier fields. ", "dimensions": { "concept": "ifrs-full:DisclosureOfDepreciationAndAmortisationExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-416": { "value": "7. Administrative expenses
2023 2022
US$\u2019000 US$\u2019000
Administrative expenses excluding transaction costs
(34,259)
(41,762)
Transaction costs
\u2013
(46,089)
(34,259)
(87,8 51)
Transactions costs in 2022 relate to the acquisitions of Marubeni Oil & Gas Limited (MOGL), Summit Exploration and Production Limited (Summit) and Siccar Point Energy entities, and costs incurred in connection to the IPO. Further details on the acquisitions can be found in note 17. The total employee benefit expenses which are either capitalised or included in cost of sales, pre-licence exploration and evaluation expenses and administrative expenses are noted below. Employee benefit expenses
2023 2022
US$\u2019000 US$\u2019000
Wages and salaries
(104,027)
(81,017)
Share-based payment charges (note 32)
(16,369)
(14,069)
Social security costs
(12,290)
(9,902)
Pension costs
(9,997)
(8,298)
(142,683)
(113,286)
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 Directors\u2019 remuneration report on pages 112 to 136. Directors\u2019 emoluments in aggregate were $13.4 million (2022: $18.1 million). The average number of employees during each year was as follows:
2023
2022
Onshore and administrative
316
268
Offshore
283
249
599
517
The increase in average employee numbers in 2023 reflects the full-year impact of acquisitions made in 2022 and the conversion of a number of contractor roles to staff positions.
Audit fees
2023 2022
US$\u2019000 US$\u2019000
Fees payable to the Company\u2019s auditor for audit of the Company\u2019s financial statements
1,286
1,095
Audit of the Company\u2019s subsidiaries pursuant to legislation
326
324
Non-audit fees provided by the auditors
205
4,707
1,817
6,126
Non-audit fees provided by the auditors for the year ended 31 December 2023 comprise audit-related assurance services of $205k (2022: $170k), other assurance services of $nil (2022: $990k) and other non-audit services of $nil
(2022: $3,547k), with the latter two captions in 2022 relating to reporting accountant workstreams in relation to the IPO.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-455": { "value": "
Employee benefit expenses
2023 2022
US$\u2019000 US$\u2019000
Wages and salaries
(104,027)
(81,017)
Share-based payment charges (note 32)
(16,369)
(14,069)
Social security costs
(12,290)
(9,902)
Pension costs
(9,997)
(8,298)
(142,683)
(113,286)
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 Directors\u2019 remuneration report on
pages 112 to 136. Directors\u2019 emoluments in aggregate were $13.4 million (2022: $18.1 million).
The average number of employees during each year was as follows:
2023
2022
Onshore and administrative
316
268
Offshore
283
249
599
517
The increase in average employee numbers in 2023 reflects the full-year impact of acquisitions made in 2022 and the conversion of a number of contractor roles to staff positions.
", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutEmployeesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-491": { "value": "Employee benefit expenses
2023 2022
US$\u2019000 US$\u2019000
Wages and salaries
(104,027)
(81,017)
Share-based payment charges (note 32)
(16,369)
(14,069)
Social security costs
(12,290)
(9,902)
Pension costs
(9,997)
(8,298)
(142,683)
(113,286)
", "dimensions": { "concept": "ifrs-full:DisclosureOfEmployeeBenefitsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-456": { "value": "Audit fees
2023 2022
US$\u2019000 US$\u2019000
Fees payable to the Company\u2019s auditor for audit of the Company\u2019s financial statements
1,286
1,095
Audit of the Company\u2019s subsidiaries pursuant to legislation
326
324
Non-audit fees provided by the auditors
205
4,707
1,817
6,126
Non-audit fees provided by the auditors for the year ended 31 December 2023 comprise audit-related assurance services of $205k (2022: $170k), other assurance services of $nil (2022: $990k) and other non-audit services of $nil (2022: $3,547k), with the latter two captions in 2022 relating to reporting accountant workstreams in relation to the IPO.", "dimensions": { "concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-417": { "value": "
8. Other gains and losses
2023 2022
US$\u2019000 US$\u2019000
Gain/(loss) on financial instruments (note 29)
43,059
(278)
Fair value losses on contingent consideration (note 25)
(8,008)
(4,295)
Remeasurements of decommissioning reimbursement receivables
5,645
\u2013
Net foreign exchange
(1,673)
(4,856)
Settlement of historic claim relating to an acquisition
50,068
\u2013
89,091
(9,429)
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 $50.1 million.
", "dimensions": { "concept": "ithacaenergyplc:DisclosureOfOtherGainsAndLosses", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-418": { "value": "
9. Finance costs and finance income
2023 2022
US$\u2019000 US$\u2019000
Loan interest and charges
(47,494)
(58,317)
Senior notes interest
(58,377)
(61,537)
Loan fee amortisation
(4,508)
(6,418)
Interest on lease liabilities (note 24)
(3,183)
(3,852)
Interest on related-party loan (note 31)
\u2013
(17,924)
Accretion
(76,162)
(56,511)
Realised gains on interest derivative contracts (note 29)
\u2013
851
Total finance costs
(189,724)
(203,708)
Interest income
5,688
695
There was no interest capitalised into qualifying assets in either the year to 31 December 2023 or the year to 31 December 2022.
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-501": { "value": "9. Finance costs and finance income
2023 2022
US$\u2019000 US$\u2019000
Loan interest and charges
(47,494)
(58,317)
Senior notes interest
(58,377)
(61,537)
Loan fee amortisation
(4,508)
(6,418)
Interest on lease liabilities (note 24)
(3,183)
(3,852)
Interest on related-party loan (note 31)
\u2013
(17,924)
Accretion
(76,162)
(56,511)
Realised gains on interest derivative contracts (note 29)
\u2013
851
Total finance costs
(189,724)
(203,708)
Interest income
5,688
695
There was no interest capitalised into qualifying assets in either the year to 31 December 2023 or the year to 31 December 2022.", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-498": { "value": "9. Finance costs and finance income
2023 2022
US$\u2019000 US$\u2019000
Loan interest and charges
(47,494)
(58,317)
Senior notes interest
(58,377)
(61,537)
Loan fee amortisation
(4,508)
(6,418)
Interest on lease liabilities (note 24)
(3,183)
(3,852)
Interest on related-party loan (note 31)
\u2013
(17,924)
Accretion
(76,162)
(56,511)
Realised gains on interest derivative contracts (note 29)
\u2013
851
Total finance costs
(189,724)
(203,708)
Interest income
5,688
695
There was no interest capitalised into qualifying assets in either the year to 31 December 2023 or the year to 31 December 2022.", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-492": { "value": "9. Finance costs and finance income
2023 2022
US$\u2019000 US$\u2019000
Loan interest and charges
(47,494)
(58,317)
Senior notes interest
(58,377)
(61,537)
Loan fee amortisation
(4,508)
(6,418)
Interest on lease liabilities (note 24)
(3,183)
(3,852)
Interest on related-party loan (note 31)
\u2013
(17,924)
Accretion
(76,162)
(56,511)
Realised gains on interest derivative contracts (note 29)
\u2013
851
Total finance costs
(189,724)
(203,708)
Interest income
5,688
695
There was no interest capitalised into qualifying assets in either the year to 31 December 2023 or the year to 31 December 2022.", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestIncomeExpenseExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-477": { "value": "9. Finance costs and finance income
2023 2022
US$\u2019000 US$\u2019000
Loan interest and charges
(47,494)
(58,317)
Senior notes interest
(58,377)
(61,537)
Loan fee amortisation
(4,508)
(6,418)
Interest on lease liabilities (note 24)
(3,183)
(3,852)
Interest on related-party loan (note 31)
\u2013
(17,924)
Accretion
(76,162)
(56,511)
Realised gains on interest derivative contracts (note 29)
\u2013
851
Total finance costs
(189,724)
(203,708)
Interest income
5,688
695
There was no interest capitalised into qualifying assets in either the year to 31 December 2023 or the year to 31 December 2022.", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceCostExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-457": { "value": "9. Finance costs and finance income
2023 2022
US$\u2019000 US$\u2019000
Loan interest and charges
(47,494)
(58,317)
Senior notes interest
(58,377)
(61,537)
Loan fee amortisation
(4,508)
(6,418)
Interest on lease liabilities (note 24)
(3,183)
(3,852)
Interest on related-party loan (note 31)
\u2013
(17,924)
Accretion
(76,162)
(56,511)
Realised gains on interest derivative contracts (note 29)
\u2013
851
Total finance costs
(189,724)
(203,708)
Interest income
5,688
695
There was no interest capitalised into qualifying assets in either the year to 31 December 2023 or the year to 31 December 2022.", "dimensions": { "concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-419": { "value": "
10. Earnings per share
The calculation of basic earnings per share is based on the profit after tax and the weighted average number of ordinary shares in issue during the year. Basic and diluted earnings per share are calculated as follows:
2023 2022
US$\u2019000 US$\u2019000
Earnings for the year:
Earnings for the purpose of basic and diluted earnings per share
215,635
1,031,532
Number of shares (million)
Weighted average number of ordinary shares for the purpose of basic earnings per share
1,006.7
1,005.2
Dilutive potential ordinary shares
12.7
5.0
Weighted average number of ordinary shares for the purpose of diluted earnings per share
1,019.4
1,010.2
Earnings per share (cents)
Basic
21.4
102.6
Diluted
21.2
102.1
1
", "dimensions": { "concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-420": { "value": "
11. Trade and other receivables
Current
2023 2022
US$\u2019000 US$\u2019000
Trade receivables
19,968
31,906
Other receivables
24,369
14,210
Joint operations receivables
91,960
99,800
Accrued income
197,993
214,078
334,290
359,994
Materially all trade and other receivables, including receivables from joint operations are not overdue by more than 90 days. The credit risk associated with trade receivables, accrued income and other receivables is considered to be
insignificant. No ECL has been recognised in the current or prior year.
Non-current
2023 2022
US$\u2019000 US$\u2019000
Decommissioning reimbursements
165,064
162,710
Current
2023 2022
US$\u2019000 US$\u2019000
Decommissioning reimbursements
30,417
38,115
Movements on decommissioning reimbursements were as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
200,825
246,824
Accretion
7,536
5,946
Reimbursements received
(22,101)
(23,418)
Change in reimbursement estimates
9,221
(28,527)
At 31 December
195,481
200,825
The decommissioning reimbursements represent the equal and opposite of decommissioning liabilities (note 23), net of tax, associated with the Heather and Strathspey fields and relates to a contractual agreement as part of the
CNSL acquisition. As part of the terms of the CNSL acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL in relation to these interests.
The Group pays the liabilities in respect of Heather and Strathspey and then receives full reimbursement from Chevron.
As these payments are virtually certain they have been accounted for under IAS 37 as a reimbursement asset.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-499": { "value": "11. Trade and other receivables Current
2023 2022
US$\u2019000 US$\u2019000
Trade receivables
19,968
31,906
Other receivables
24,369
14,210
Joint operations receivables
91,960
99,800
Accrued income
197,993
214,078
334,290
359,994
Materially all trade and other receivables, including receivables from joint operations are not overdue by more than 90 days. The credit risk associated with trade receivables, accrued income and other receivables is considered to be insignificant. No ECL has been recognised in the current or prior year. Non-current
2023 2022
US$\u2019000 US$\u2019000
Decommissioning reimbursements
165,064
162,710
Current
2023 2022
US$\u2019000 US$\u2019000
Decommissioning reimbursements
30,417
38,115
Movements on decommissioning reimbursements were as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
200,825
246,824
Accretion
7,536
5,946
Reimbursements received
(22,101)
(23,418)
Change in reimbursement estimates
9,221
(28,527)
At 31 December
195,481
200,825
The decommissioning reimbursements represent the equal and opposite of decommissioning liabilities (note 23), net of tax, associated with the Heather and Strathspey fields and relates to a contractual agreement as part of the CNSL acquisition. As part of the terms of the CNSL acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL in relation to these interests. The Group pays the liabilities in respect of Heather and Strathspey and then receives full reimbursement from Chevron. As these payments are virtually certain they have been accounted for under IAS 37 as a reimbursement asset. 12. Prepaid expenses and decommissioning securities Current
2023 2022
US$\u2019000 US$\u2019000
Prepayments
34,355
7,415
Decommissioning securities
3,323
1,640
37,678
9,055
27. Taxation
2023 2022
US$\u2019000 US$\u2019000
Current tax
Current corporation tax charge
(39,308)
(54,557)
Current EPL tax charge
(333,425)
(131,389)
Current corporation tax (charge)/credit \u2013 prior year
(17,426)
1,839
Total current tax charge
(390,159)
(184,107)
Deferred tax
Adjustment in respect of prior period
6,370
(641)
Group tax credit/(charge) in consolidated statement of profit or loss
227,360
(1,013,817)
Group tax charge in consolidated statement of other comprehensive income
(71,700)
(200,455)
Total deferred tax credit/(charge)
162,030
(1,214,913)
Deferred Petroleum Revenue Tax
Deferred PRT credit/(charge) in statement of profit or loss
70,037
(10,432)
Total tax charge through consolidated statement of profit or loss
(86,392)
(1,208,997)
The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:
2023 2022
US$\u2019000 US$\u2019000
Accounting profit before tax
302,027
2,240,529
At tax rate of 40% (2022: 40%)
(120,811)
(896,211)
Non-deductible expense
(34,578)
(53,548)
Recognition of non-taxable gain on bargain purchase
\u2013
534,069
Financing costs not allowed for SCT
(704)
(1,958)
Ring Fence Expenditure Supplement
102,866
155,113
Deferred tax effect of investment allowance
56,930
(20,615)
Prior year adjustment
(11,673)
1,198
Deferred PRT net of corporation tax
42,022
(6,259)
Deferred tax on EPL
215,910
(766,489)
Current tax on EPL
(333,425)
(131,389)
Prior year adjustments on acquired entities
\u2013
(3,165)
Share-based payments
1,945
\u2013
Unrecognised tax losses
(4,874)
(19,743)
Total tax charge recorded in the consolidated statement of profit or loss
(86,392)
(1,208,997)
The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in both 2023 and 2022, prior to the introduction of the EPL, was 40% (2022: 40%) consisting of a Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include 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. The credit arising in 2023 of $42.0 million was principally due the impairment of the Alba field due to forecast future production volumes. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK however adjustments to recognised deferred PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The EPL was enacted in July 2022 with effect from 26 May 2022, at a headline rate of 25% which increased the effective UK Ring Fenced oil and gas rate to 65% until 2025, resulting in additional current and deferred tax charges in the year to 31 December 2022. Further changes to the EPL were announced on 17 November 2022 and enacted in December 2022 whereby the Levy was increased to 35% from 1 January 2023 until 31 March 2028, increasing the effective UK Ring Fenced oil and gas tax rate to 75% resulting in an additional deferred tax charge during the year to 31 December 2022. Deferred tax at 31 December relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Deferred corporation tax liability
(1,944,941)
(2,258,813)
Deferred corporation tax asset
2,480,921
2,629,548
Deferred PRT asset
91,759
21,721
Net deferred tax asset
627,738
392,456
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. Non-oil and gas losses of $251 million (2022: $156 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses. The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
392,456
220,918
Profit or loss credit/(charge)
303,767
(1,024,889)
Other comprehensive income charge
(71,700)
(200,455)
Deferred tax on decommissioning reimbursements (note 11)
3,214
\u2013
Business combinations (note 17)
\u2013
1,396,882
At 31 December
627,738
392,456
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Accelerated capital allowances
438,359
(490,246)
Tax losses
(216,937)
(386,819)
Decommissioning provision
52,440
(124,598)
Deferred PRT
(28,015)
4,173
Hedging
(101,744)
(226,040)
Share schemes
3,978
\u2013
Investment allowances
13,950
8,617
162,030
(1,214,913)
Gross deferred corporation tax liabilities
Deferred
corporation tax on Accelerated tax
Hedges deferred PRT depreciation Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
(12,861)
(675,279)
(688,140)
Prior year adjustment
\u2013
\u2013
(4,347)
(4,347)
Reclassification of decommissioning asset
\u2013
\u2013
(436,771)
(436,771)
Business combinations
\u2013
\u2013
(647,743)
(6 47,74
3)
Origination and reversal of temporary differences
\u2013
4,173
(485,985)
(481,812)
At 31 December 2022 and 1 January 2023
\u2013
(8,688)
(2,250,125)
(2,258,813)
Reclass to deferred corporation tax assets
(8,678)
\u2013
\u2013
(8,678)
Prior year adjustment
2,721
\u2013
8,307
11,028
Origination and reversal of temporary differences
(101,744)
(28,015)
441,281
311,522
At 31 December 2023
(107,701)
(36,703)
(1,800,537)
(1,944,941)
Gross deferred corporation tax assets
Decommissioning
Share schemes provision Tax losses Hedges Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
197,666
500,282
178,956
876,904
Prior year adjustment
\u2013
\u2013
3,706
\u2013
3,706
Reclassification of decommissioning asset
\u2013
436,772
\u2013
\u2013
436,772
Business combinations
\u2013
156,212
1,858,706
38,406
2,053,324
Origination and reversal of temporary differences
\u2013
(124,598)
(390,520)
(226,040)
(741,158)
At 31 December 2022 and 1 January 2023
\u2013
666,052
1,972,174
(8,678)
2,629,548
Reclass from deferred corporation tax liabilities
\u2013
\u2013
\u2013
8,678
8,678
Prior year adjustment
177
\u2013
(4,989)
\u2013
(4,812)
Origination and reversal of temporary differences
3,802
55,654
(211,949)
\u2013
(152,493)
At 31 December 2023
3,979
721,706
1,755,236
\u2013
2,480,921
Total
Deferred PRT asset US$\u2019000
At 1 January 2022
32,154
Origination and reversal of temporary differences
(10,433)
At 31 December 2022 and 1 January 2023
21,721
Origination and reversal of temporary differences
70,037
At 31 December 2023
91,758
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2023 of $536 million and $92 million respectively (2022: $371 million and $21 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 a restructuring exercise to move certain assets between Group entities which has 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 upon 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. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million. On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective for all accounting periods starting on or after 31 December 2023. The Group does not anticipate that the adoption of this will have a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate. The Group has applied the exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and therefore there is no impact on the tax values reported.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-478": { "value": "11. Trade and other receivables Current
2023 2022
US$\u2019000 US$\u2019000
Trade receivables
19,968
31,906
Other receivables
24,369
14,210
Joint operations receivables
91,960
99,800
Accrued income
197,993
214,078
334,290
359,994
Materially all trade and other receivables, including receivables from joint operations are not overdue by more than 90 days. The credit risk associated with trade receivables, accrued income and other receivables is considered to be insignificant. No ECL has been recognised in the current or prior year. Non-current
2023 2022
US$\u2019000 US$\u2019000
Decommissioning reimbursements
165,064
162,710
Current
2023 2022
US$\u2019000 US$\u2019000
Decommissioning reimbursements
30,417
38,115
Movements on decommissioning reimbursements were as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
200,825
246,824
Accretion
7,536
5,946
Reimbursements received
(22,101)
(23,418)
Change in reimbursement estimates
9,221
(28,527)
At 31 December
195,481
200,825
The decommissioning reimbursements represent the equal and opposite of decommissioning liabilities (note 23), net of tax, associated with the Heather and Strathspey fields and relates to a contractual agreement as part of the CNSL acquisition. As part of the terms of the CNSL acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL in relation to these interests. The Group pays the liabilities in respect of Heather and Strathspey and then receives full reimbursement from Chevron. As these payments are virtually certain they have been accounted for under IAS 37 as a reimbursement asset. ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherNoncurrentAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-458": { "value": "11. Trade and other receivables Current
2023 2022
US$\u2019000 US$\u2019000
Trade receivables
19,968
31,906
Other receivables
24,369
14,210
Joint operations receivables
91,960
99,800
Accrued income
197,993
214,078
334,290
359,994
Materially all trade and other receivables, including receivables from joint operations are not overdue by more than 90 days. The credit risk associated with trade receivables, accrued income and other receivables is considered to be insignificant. No ECL has been recognised in the current or prior year. Non-current
2023 2022
US$\u2019000 US$\u2019000
Decommissioning reimbursements
165,064
162,710
Current
2023 2022
US$\u2019000 US$\u2019000
Decommissioning reimbursements
30,417
38,115
Movements on decommissioning reimbursements were as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
200,825
246,824
Accretion
7,536
5,946
Reimbursements received
(22,101)
(23,418)
Change in reimbursement estimates
9,221
(28,527)
At 31 December
195,481
200,825
The decommissioning reimbursements represent the equal and opposite of decommissioning liabilities (note 23), net of tax, associated with the Heather and Strathspey fields and relates to a contractual agreement as part of the CNSL acquisition. As part of the terms of the CNSL acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL in relation to these interests. The Group pays the liabilities in respect of Heather and Strathspey and then receives full reimbursement from Chevron. As these payments are virtually certain they have been accounted for under IAS 37 as a reimbursement asset. ", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherCurrentAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-421": { "value": "12. Prepaid expenses and decommissioning securities Current
2023 2022
US$\u2019000 US$\u2019000
Prepayments
34,355
7,415
Decommissioning securities
3,323
1,640
37,678
9,055
", "dimensions": { "concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-422": { "value": "
13. Inventories
Current
2023 2022
US$\u2019000 US$\u2019000
Hydrocarbon underlift
60,427
87, 563
Materials inventories
125,674
124,755
Provision for obsolete materials inventory
(35,605)
(35,437)
150,496
176,881
", "dimensions": { "concept": "ifrs-full:DisclosureOfInventoriesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-423": { "value": "
14. Exploration and evaluation assets
US$\u2019000
At 1 January 2022
116,355
Additions
42,168
Acquisitions (note 17)
706,558
Transfers to development and production assets (note 15)
(75,005)
Write offs/relinquishments
(14,303)
At 31 December 2022 and 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
548,354
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 $13.6 million being expensed in the year to 31 December 2023 (2022: $14.3 million).
The transfers from exploration and evaluation assets to development and production assets in 2023 relates to the Rosebank development. Transfers in 2022 related to the Abigail and Jade South wells.
Included within additions in the year is equity acquired in the Cambo and Fotla developments acquired from Shell U.K. Limited and Spirit Energy Resources Limited respectively.
The write offs/relinquishments includes $nil (2022: $5.3 million) impairment relating to decommissioning revisions.
The principal component of exploration and evaluation assets at 31 December 2023 is the Cambo field with a carrying value of $391 million (2022: Cambo $364 million and Rosebank $315 million) which formed part of the
Siccar acquisition (see note 17).
", "dimensions": { "concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-424": { "value": "
15. Property, plant and equipment
Right-of-use Development and Other
operating assets production assets fixed assets Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Cost
At 1 January 2022
9,210
5,838,178
40,293
5,887,681
Additions
89,717
362,844
5,619
458,180
Acquisitions (note 17)
\u2013
1,115,023
\u2013
1,115,023
Transfers from exploration and evaluation assets (note 14)
\u2013
75,005
\u2013
75,005
Change in decommissioning estimates (note 23)
\u2013
(278,398)
\u2013
(278,398)
At 31 December 2022 and 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
156,169
7,976,764
47,64
0
8,180,573
Depletion, depreciation, amortisation and impairment
At 1 January 2022
(5,429)
(2,909,695)
(13,824)
(2,928,948)
Depletion, depreciation and amortisation charge for the year
(37,438)
(615,261)
(10,248)
(662,947)
Impairment charge (note 19)
\u2013
(30,700)
\u2013
(30,700)
At 31 December 2022 and 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
(85,515)
(4,808,701)
(28,151)
(4,922,367)
Net book value at 31 December 2022
56,060
3,556,996
21,840
3,634,896
Net book value at 31 December 2023
70,654
3,168,063
19,489
3,258,206
The transfers from exploration and evaluation assets to 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. Subsequent to this, environmental campaigners Uplift and Greenpeace UK announced that they are separately seeking judicial review by the Court of Session in Edinburgh with respect to the decision
by the NSTA and the Secretary of State for Energy to approve the Rosebank development. In 2022 the transfers related to the Abigail and Jade South wells. At the point of transfer these assets were tested for impairment and none
was found.
Additions to right of use assets in 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 includes buildings, computer equipment, office equipment and furniture and fittings.
", "dimensions": { "concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-425": { "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
2023
2022
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.6 72
Jade
Chrysaor Petroleum Company UK Limited
25.50%
25.50%
22/30c and 29/5c
P.666
Elgin-Franklin
TotalEnergies E&P UK Limited
6.09%
6.09%
15/29b
P.59 0
Callanish
Chrysaor Production (UK) 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
6.09%
6.09%
21/4a
P.3 47
Callanish
Chrysaor Production (UK) 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 Sinopec Resources UK Limited
41.03%
41.03%
22/17s, 22/22a and 22/23a
P.291
Arbroath, Arkwright, Brechin, Carnoustie, Cayley, Shaw
Repsol Sinopec Resources UK Limited
41.03%
41.03%
23/26b
P.26 4
Erskine
Ithaca Energy (UK) Limited
50.00%
50.00%
9/11d and 9/12b
P. 2 5 0 8
Mariner
Equinor UK Limited
8.89%
8.89%
22/1b
P. 2 37 3
F Block (Fotla and Fortriu)
Ithaca Oil and Gas Limited
100.00%
60.00%
15/18b
P.2158
Marigold
Ithaca Oil and Gas Limited
100.00%
100.00%
9/11g
P. 2151
Mariner
Equinor UK Limited
8.89%
8.89%
16/26a A-ALB
P.21 3
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.20 3
Columba E
CNR International (UK) Limited
20.00%
20.00%
3/8a and 3/8a
P.1 9 9
Columba B/D
CNR International (UK) Limited
5.60%
5.60%
Group net % interest
Block
Licence
Field/discovery name
Operator
2023
2022
22/30b
P.1 8 8
Elgin-Franklin
TotalEnergies E&P UK Limited
6.09%
6.09%
21/20a
P.185
Cook
Ithaca SP E&P Limited
61.35%
61.35%
8/15a
P.17 58
Mariner
Equinor UK Limited
8.89%
8.89%
29/10b
P.16 65
Abigail
Ithaca SP E&P Limited
100.00%
100.00%
30/7b
P.1589
Jade
Chrysaor Petroleum Company UK Limited
25.50%
25.50%
30/1f
P.158 8
Vorlich
Ithaca MA Limited
100.00%
100.00%
30/1c
P. 3 63
Vorlich
Ithaca MA Limited
34.00%
34.00%
205/2a
P.1272
Rosebank
Equinor UK Limited
20.00%
20.00%
205/1a
P.11 91
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%
204/4a and 204/5a
P.1189
Cambo
Ithaca SP E&P Limited
100.00%
70.00%
21/3a
P.118
Brodgar
Chrysaor Production (UK) Limited
25.00%
25.00%
23/22a
P.111
Pierce
Enterprise Oil Limited
34.01%
34.01%
15/30a
P.10 3
Britannia
Chrysaor Production (UK) Limited
33.03%
33.03%
21/5a
P.10 3
Enochdhu
Chrysaor Production (UK) Limited
50.00%
50.00%
204/9a and 204/10a
P.1028
Cambo
Ithaca SP E&P Limited
100.00%
70.00%
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 Sinopec Resources UK Limited
41.03%
41.03%
22/17n, 22/17s, 22/22a and 22/23a
P.019
Godwin, Montrose
Repsol Sinopec Resources UK Limited
41.03%
41.03%
30/6a and 29/10a
P.011
Stella/Harrier
Ithaca Energy (UK) Limited
100.00%
100.00%
30/11a and 30/12d
P.18 20
Isabella
Total Energies E&P North Sea UK Limited
10.00%
10.00%
204/8, 204/9c, 204/10c, 204/13, 204/14d
P.24 0 3
Tornado
Ithaca SP E&P Limited
50.00%
50.00%
and 204/15
", "dimensions": { "concept": "ifrs-full:DisclosureOfJointVenturesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-493": { "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
2023
2022
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.6 72
Jade
Chrysaor Petroleum Company UK Limited
25.50%
25.50%
22/30c and 29/5c
P.666
Elgin-Franklin
TotalEnergies E&P UK Limited
6.09%
6.09%
15/29b
P.59 0
Callanish
Chrysaor Production (UK) 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
6.09%
6.09%
21/4a
P.3 47
Callanish
Chrysaor Production (UK) 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 Sinopec Resources UK Limited
41.03%
41.03%
22/17s, 22/22a and 22/23a
P.291
Arbroath, Arkwright, Brechin, Carnoustie, Cayley, Shaw
Repsol Sinopec Resources UK Limited
41.03%
41.03%
23/26b
P.26 4
Erskine
Ithaca Energy (UK) Limited
50.00%
50.00%
9/11d and 9/12b
P. 2 5 0 8
Mariner
Equinor UK Limited
8.89%
8.89%
22/1b
P. 2 37 3
F Block (Fotla and Fortriu)
Ithaca Oil and Gas Limited
100.00%
60.00%
15/18b
P.2158
Marigold
Ithaca Oil and Gas Limited
100.00%
100.00%
9/11g
P. 2151
Mariner
Equinor UK Limited
8.89%
8.89%
16/26a A-ALB
P.21 3
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.20 3
Columba E
CNR International (UK) Limited
20.00%
20.00%
3/8a and 3/8a
P.1 9 9
Columba B/D
CNR International (UK) Limited
5.60%
5.60%
Group net % interest
Block
Licence
Field/discovery name
Operator
2023
2022
22/30b
P.1 8 8
Elgin-Franklin
TotalEnergies E&P UK Limited
6.09%
6.09%
21/20a
P.185
Cook
Ithaca SP E&P Limited
61.35%
61.35%
8/15a
P.17 58
Mariner
Equinor UK Limited
8.89%
8.89%
29/10b
P.16 65
Abigail
Ithaca SP E&P Limited
100.00%
100.00%
30/7b
P.1589
Jade
Chrysaor Petroleum Company UK Limited
25.50%
25.50%
30/1f
P.158 8
Vorlich
Ithaca MA Limited
100.00%
100.00%
30/1c
P. 3 63
Vorlich
Ithaca MA Limited
34.00%
34.00%
205/2a
P.1272
Rosebank
Equinor UK Limited
20.00%
20.00%
205/1a
P.11 91
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%
204/4a and 204/5a
P.1189
Cambo
Ithaca SP E&P Limited
100.00%
70.00%
21/3a
P.118
Brodgar
Chrysaor Production (UK) Limited
25.00%
25.00%
23/22a
P.111
Pierce
Enterprise Oil Limited
34.01%
34.01%
15/30a
P.10 3
Britannia
Chrysaor Production (UK) Limited
33.03%
33.03%
21/5a
P.10 3
Enochdhu
Chrysaor Production (UK) Limited
50.00%
50.00%
204/9a and 204/10a
P.1028
Cambo
Ithaca SP E&P Limited
100.00%
70.00%
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 Sinopec Resources UK Limited
41.03%
41.03%
22/17n, 22/17s, 22/22a and 22/23a
P.019
Godwin, Montrose
Repsol Sinopec Resources UK Limited
41.03%
41.03%
30/6a and 29/10a
P.011
Stella/Harrier
Ithaca Energy (UK) Limited
100.00%
100.00%
30/11a and 30/12d
P.18 20
Isabella
Total Energies E&P North Sea UK Limited
10.00%
10.00%
204/8, 204/9c, 204/10c, 204/13, 204/14d
P.24 0 3
Tornado
Ithaca SP E&P Limited
50.00%
50.00%
and 204/15
17. Business combinations There were no acquisitions during 2023. In 2022, the fair values of the identifiable assets and liabilities as at the acquisition dates were:
MOGL Siccar Summit
2022 2022 2022
US$\u2019000 US$\u2019000 US$\u2019000
Property, plant and equipment (note 15)
322,590
668,700
101,933
Exploration and evaluation assets (note 14)
\u2013
706,558
\u2013
Cash
170,629
88,638
18,799
Inventory
2,781
\u2013
\u2013
Trade and other receivables
36,617
32,627
10,513
532,617
1,496,523
131,245
Trade and other payables
(5,436)
(52,616)
(20,407)
Oil inventory overlift
\u2013
(2,626)
(2,806)
Decommissioning provisions
(253,393)
(121,022)
(16,116)
Financial instruments
\u2013
(82,899)
\u2013
Borrowings
\u2013
(200,000)
\u2013
(258,829)
(459,163)
(39,329)
Deferred tax asset
742,281
1,334,221
6,446
Deferred tax liability
(86,001)
(550,103)
(40,773)
656,280
784,118
(34,327)
Total identifiable net assets at fair value
930,068
1,821,478
57,589
Consideration satisfied by cash
(107,811)
(1,015,346)
(119,362)
Deferred consideration
(63,415)
\u2013
\u2013
Contingent consideration
(139,320)
(102,111)
\u2013
Consideration
(310,546)
(1,117,457)
(119,362)
Gain on bargain purchase/(goodwill) arising on acquisition
619,522
704,021
(61,773)
Net cash flows relating to acquisition
62,818
(926,708)
(100,563)
1 1. Net cash flows relating to the MOGL acquisition includes a $7 million deposit paid in the year ended 31 December 2021. MOGL On 4 February 2022, the Group completed the acquisition of 100% of the issued share capital of MOGL. The transaction added a further non-operated share in nine producing field interests (known as MonArb) to the existing Ithaca portfolio. Taking into account the interim period cash flows generated by MOGL since the transaction effective date of 1 January 2021, the $7 million deposit paid at signing of the transaction in November 2021 and conventional working capital adjustments, the price payable at completion of the acquisition was $108 million. A deferred consideration of $63 million and risked contingent consideration of $139 million, discounted at 2.5% were recognised at acquisition, resulting in a gain on bargain purchase of $620 million. The contingent consideration arrangement on 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 contingent consideration is subsequently revalued at each year-end date. The gain on bargain purchase arising on the MOGL acquisition was principally a result of recognising a deferred tax asset arising from tax losses of $745 million, which were not forecast to be utilised by MOGL, as allowed under IFRS 3 fair value accounting for business combinations. The gain was also partially attributed to the extended period from effective date of 1 January 2021 to the completion date of 4 February 2022 during which time hydrocarbon prices rose significantly. The gain on bargain purchase of $620 million was credited to income in the year ended 31 December 2022. Siccar Point Energy On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Siccar Point Energy (Holdings) Limited (Siccar Point Energy) and its UK subsidiaries. The transaction added a further two producing assets (Mariner 8.89% and Schiehallion 11.75%), an additional 5.57% increase to the Group\u2019s existing equity in Jade, and three development prospects (Rosebank 20%, Cambo 70% at date of acquisition and Tornado 50%) to the existing Group portfolio. Taking into account the interim period cash flows generated by Siccar since the transaction effective date of 1 January 2022 and conventional working capital adjustments, the price payable at completion of the acquisition was $1.015 billion. A risked contingent consideration of $102 million was recognised, resulting in a gain on bargain purchase of $704 million. The contingent consideration arrangement on Siccar Point Energy depends on whether various milestones of the SPA are met as follows: redemption of acquired bond as at repayment date, 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 contingent consideration is subsequently revalued at each year-end date. The gain on bargain purchase arising on the Siccar Point Energy transaction was principally as a result of recognising a deferred tax asset arising from tax losses of $1,334 million as allowed under IFRS 3 fair value accounting for business combinations. The gain on bargain purchase of $704 million was credited to income in the year ended 31 December 2022. On acquisition of Siccar Point Energy, the Group acquired a $200 million bond. On 28 July 2022 a Group of bondholders exercised their right to redeem and subsequently $166.4 million was paid to these bondholders. Subsequently, in September 2022, notes totalling $25.6 million were bought back at a premium of 6% by the Group. The remaining notes totalling $8.0 million were redeemed on 12 October 2022 and there was no remaining balance at 31 December 2022. Summit On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Summit. The transaction added a further 2.1875% ownership of the Elgin Franklin field interest within the existing Group portfolio. Taking into account the interim period cash flows generated by Summit since the transaction effective date of 1 January 2021, the $10 million deposit paid at signing of the transaction in February 2022 and conventional working capital adjustments, the price payable at completion of the acquisition was $119 million and goodwill of $62 million was recognised. The goodwill recognised can be attributed to the increase in the Group\u2019s equity interest in the Elgin Franklin field and the corresponding impact of EPL, which was announced between effective date and completion, on the fair values at acquisition. There are no contingent consideration arrangements under the Sale and Purchase Agreement of the Summit assets. No contingent liabilities have been acquired on the business combinations detailed above. The fair values of the oil and gas assets and the intangible assets acquired 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 each 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 operator cost estimates with reference to observable market data. 31. Related-party transactions The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) who owns 88.55% of the issued share capital of Ithaca Energy plc. The registered office address of the DKL Energy Limited is 47 Esplanade, St Helier, Jersey, JE1 0BD. 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. 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
2023
2022
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%
Transactions between subsidiaries are eliminated on consolidation. 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 ", "dimensions": { "concept": "ifrs-full:DisclosureOfInterestsInOtherEntitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-479": { "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
2023
2022
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.6 72
Jade
Chrysaor Petroleum Company UK Limited
25.50%
25.50%
22/30c and 29/5c
P.666
Elgin-Franklin
TotalEnergies E&P UK Limited
6.09%
6.09%
15/29b
P.59 0
Callanish
Chrysaor Production (UK) 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
6.09%
6.09%
21/4a
P.3 47
Callanish
Chrysaor Production (UK) 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 Sinopec Resources UK Limited
41.03%
41.03%
22/17s, 22/22a and 22/23a
P.291
Arbroath, Arkwright, Brechin, Carnoustie, Cayley, Shaw
Repsol Sinopec Resources UK Limited
41.03%
41.03%
23/26b
P.26 4
Erskine
Ithaca Energy (UK) Limited
50.00%
50.00%
9/11d and 9/12b
P. 2 5 0 8
Mariner
Equinor UK Limited
8.89%
8.89%
22/1b
P. 2 37 3
F Block (Fotla and Fortriu)
Ithaca Oil and Gas Limited
100.00%
60.00%
15/18b
P.2158
Marigold
Ithaca Oil and Gas Limited
100.00%
100.00%
9/11g
P. 2151
Mariner
Equinor UK Limited
8.89%
8.89%
16/26a A-ALB
P.21 3
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.20 3
Columba E
CNR International (UK) Limited
20.00%
20.00%
3/8a and 3/8a
P.1 9 9
Columba B/D
CNR International (UK) Limited
5.60%
5.60%
Group net % interest
Block
Licence
Field/discovery name
Operator
2023
2022
22/30b
P.1 8 8
Elgin-Franklin
TotalEnergies E&P UK Limited
6.09%
6.09%
21/20a
P.185
Cook
Ithaca SP E&P Limited
61.35%
61.35%
8/15a
P.17 58
Mariner
Equinor UK Limited
8.89%
8.89%
29/10b
P.16 65
Abigail
Ithaca SP E&P Limited
100.00%
100.00%
30/7b
P.1589
Jade
Chrysaor Petroleum Company UK Limited
25.50%
25.50%
30/1f
P.158 8
Vorlich
Ithaca MA Limited
100.00%
100.00%
30/1c
P. 3 63
Vorlich
Ithaca MA Limited
34.00%
34.00%
205/2a
P.1272
Rosebank
Equinor UK Limited
20.00%
20.00%
205/1a
P.11 91
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%
204/4a and 204/5a
P.1189
Cambo
Ithaca SP E&P Limited
100.00%
70.00%
21/3a
P.118
Brodgar
Chrysaor Production (UK) Limited
25.00%
25.00%
23/22a
P.111
Pierce
Enterprise Oil Limited
34.01%
34.01%
15/30a
P.10 3
Britannia
Chrysaor Production (UK) Limited
33.03%
33.03%
21/5a
P.10 3
Enochdhu
Chrysaor Production (UK) Limited
50.00%
50.00%
204/9a and 204/10a
P.1028
Cambo
Ithaca SP E&P Limited
100.00%
70.00%
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 Sinopec Resources UK Limited
41.03%
41.03%
22/17n, 22/17s, 22/22a and 22/23a
P.019
Godwin, Montrose
Repsol Sinopec Resources UK Limited
41.03%
41.03%
30/6a and 29/10a
P.011
Stella/Harrier
Ithaca Energy (UK) Limited
100.00%
100.00%
30/11a and 30/12d
P.18 20
Isabella
Total Energies E&P North Sea UK Limited
10.00%
10.00%
204/8, 204/9c, 204/10c, 204/13, 204/14d
P.24 0 3
Tornado
Ithaca SP E&P Limited
50.00%
50.00%
and 204/15
17. Business combinations There were no acquisitions during 2023. In 2022, the fair values of the identifiable assets and liabilities as at the acquisition dates were:
MOGL Siccar Summit
2022 2022 2022
US$\u2019000 US$\u2019000 US$\u2019000
Property, plant and equipment (note 15)
322,590
668,700
101,933
Exploration and evaluation assets (note 14)
\u2013
706,558
\u2013
Cash
170,629
88,638
18,799
Inventory
2,781
\u2013
\u2013
Trade and other receivables
36,617
32,627
10,513
532,617
1,496,523
131,245
Trade and other payables
(5,436)
(52,616)
(20,407)
Oil inventory overlift
\u2013
(2,626)
(2,806)
Decommissioning provisions
(253,393)
(121,022)
(16,116)
Financial instruments
\u2013
(82,899)
\u2013
Borrowings
\u2013
(200,000)
\u2013
(258,829)
(459,163)
(39,329)
Deferred tax asset
742,281
1,334,221
6,446
Deferred tax liability
(86,001)
(550,103)
(40,773)
656,280
784,118
(34,327)
Total identifiable net assets at fair value
930,068
1,821,478
57,589
Consideration satisfied by cash
(107,811)
(1,015,346)
(119,362)
Deferred consideration
(63,415)
\u2013
\u2013
Contingent consideration
(139,320)
(102,111)
\u2013
Consideration
(310,546)
(1,117,457)
(119,362)
Gain on bargain purchase/(goodwill) arising on acquisition
619,522
704,021
(61,773)
Net cash flows relating to acquisition
62,818
(926,708)
(100,563)
1 1. Net cash flows relating to the MOGL acquisition includes a $7 million deposit paid in the year ended 31 December 2021. MOGL On 4 February 2022, the Group completed the acquisition of 100% of the issued share capital of MOGL. The transaction added a further non-operated share in nine producing field interests (known as MonArb) to the existing Ithaca portfolio. Taking into account the interim period cash flows generated by MOGL since the transaction effective date of 1 January 2021, the $7 million deposit paid at signing of the transaction in November 2021 and conventional working capital adjustments, the price payable at completion of the acquisition was $108 million. A deferred consideration of $63 million and risked contingent consideration of $139 million, discounted at 2.5% were recognised at acquisition, resulting in a gain on bargain purchase of $620 million. The contingent consideration arrangement on 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 contingent consideration is subsequently revalued at each year-end date. The gain on bargain purchase arising on the MOGL acquisition was principally a result of recognising a deferred tax asset arising from tax losses of $745 million, which were not forecast to be utilised by MOGL, as allowed under IFRS 3 fair value accounting for business combinations. The gain was also partially attributed to the extended period from effective date of 1 January 2021 to the completion date of 4 February 2022 during which time hydrocarbon prices rose significantly. The gain on bargain purchase of $620 million was credited to income in the year ended 31 December 2022. Siccar Point Energy On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Siccar Point Energy (Holdings) Limited (Siccar Point Energy) and its UK subsidiaries. The transaction added a further two producing assets (Mariner 8.89% and Schiehallion 11.75%), an additional 5.57% increase to the Group\u2019s existing equity in Jade, and three development prospects (Rosebank 20%, Cambo 70% at date of acquisition and Tornado 50%) to the existing Group portfolio. Taking into account the interim period cash flows generated by Siccar since the transaction effective date of 1 January 2022 and conventional working capital adjustments, the price payable at completion of the acquisition was $1.015 billion. A risked contingent consideration of $102 million was recognised, resulting in a gain on bargain purchase of $704 million. The contingent consideration arrangement on Siccar Point Energy depends on whether various milestones of the SPA are met as follows: redemption of acquired bond as at repayment date, 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 contingent consideration is subsequently revalued at each year-end date. The gain on bargain purchase arising on the Siccar Point Energy transaction was principally as a result of recognising a deferred tax asset arising from tax losses of $1,334 million as allowed under IFRS 3 fair value accounting for business combinations. The gain on bargain purchase of $704 million was credited to income in the year ended 31 December 2022. On acquisition of Siccar Point Energy, the Group acquired a $200 million bond. On 28 July 2022 a Group of bondholders exercised their right to redeem and subsequently $166.4 million was paid to these bondholders. Subsequently, in September 2022, notes totalling $25.6 million were bought back at a premium of 6% by the Group. The remaining notes totalling $8.0 million were redeemed on 12 October 2022 and there was no remaining balance at 31 December 2022. Summit On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Summit. The transaction added a further 2.1875% ownership of the Elgin Franklin field interest within the existing Group portfolio. Taking into account the interim period cash flows generated by Summit since the transaction effective date of 1 January 2021, the $10 million deposit paid at signing of the transaction in February 2022 and conventional working capital adjustments, the price payable at completion of the acquisition was $119 million and goodwill of $62 million was recognised. The goodwill recognised can be attributed to the increase in the Group\u2019s equity interest in the Elgin Franklin field and the corresponding impact of EPL, which was announced between effective date and completion, on the fair values at acquisition. There are no contingent consideration arrangements under the Sale and Purchase Agreement of the Summit assets. No contingent liabilities have been acquired on the business combinations detailed above. The fair values of the oil and gas assets and the intangible assets acquired 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 each 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 operator cost estimates with reference to observable market data. 31. Related-party transactions The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) who owns 88.55% of the issued share capital of Ithaca Energy plc. The registered office address of the DKL Energy Limited is 47 Esplanade, St Helier, Jersey, JE1 0BD. 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. 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
2023
2022
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%
Transactions between subsidiaries are eliminated on consolidation. 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 ", "dimensions": { "concept": "ifrs-full:DisclosureOfInvestmentsAccountedForUsingEquityMethodExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-426": { "value": "
17. Business combinations
There were no acquisitions during 2023. In 2022, the fair values of the identifiable assets and liabilities as at the acquisition dates were:
MOGL Siccar Summit
2022 2022 2022
US$\u2019000 US$\u2019000 US$\u2019000
Property, plant and equipment (note 15)
322,590
668,700
101,933
Exploration and evaluation assets (note 14)
\u2013
706,558
\u2013
Cash
170,629
88,638
18,799
Inventory
2,781
\u2013
\u2013
Trade and other receivables
36,617
32,627
10,513
532,617
1,496,523
131,245
Trade and other payables
(5,436)
(52,616)
(20,407)
Oil inventory overlift
\u2013
(2,626)
(2,806)
Decommissioning provisions
(253,393)
(121,022)
(16,116)
Financial instruments
\u2013
(82,899)
\u2013
Borrowings
\u2013
(200,000)
\u2013
(258,829)
(459,163)
(39,329)
Deferred tax asset
742,281
1,334,221
6,446
Deferred tax liability
(86,001)
(550,103)
(40,773)
656,280
784,118
(34,327)
Total identifiable net assets at fair value
930,068
1,821,478
57,589
Consideration satisfied by cash
(107,811)
(1,015,346)
(119,362)
Deferred consideration
(63,415)
\u2013
\u2013
Contingent consideration
(139,320)
(102,111)
\u2013
Consideration
(310,546)
(1,117,457)
(119,362)
Gain on bargain purchase/(goodwill) arising on acquisition
619,522
704,021
(61,773)
Net cash flows relating to acquisition
62,818
(926,708)
(100,563)
1
1. Net cash flows relating to the MOGL acquisition includes a $7 million deposit paid in the year ended 31 December 2021.
MOGL
On 4 February 2022, the Group completed the acquisition of 100% of the issued share capital of MOGL. The transaction added a further non-operated share in nine producing field interests (known as MonArb) to the existing
Ithaca portfolio.
Taking into account the interim period cash flows generated by MOGL since the transaction effective date of 1 January 2021, the $7 million deposit paid at signing of the transaction in November 2021 and conventional working capital
adjustments, the price payable at completion of the acquisition was $108 million. A deferred consideration of $63 million and risked contingent consideration of $139 million, discounted at 2.5% were recognised at acquisition, resulting
in a gain on bargain purchase of $620 million.
The contingent consideration arrangement on 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 contingent consideration is subsequently revalued at each year-end date.
The gain on bargain purchase arising on the MOGL acquisition was principally a result of recognising a deferred tax asset arising from tax losses of $745 million, which were not forecast to be utilised by MOGL, as allowed under IFRS 3
fair value accounting for business combinations. The gain was also partially attributed to the extended period from effective date of 1 January 2021 to the completion date of 4 February 2022 during which time hydrocarbon prices rose
significantly. The gain on bargain purchase of $620 million was credited to income in the year ended 31 December 2022.
Siccar Point Energy
On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Siccar Point Energy (Holdings) Limited (Siccar Point Energy) and its UK subsidiaries. The transaction added a further two producing assets
(Mariner 8.89% and Schiehallion 11.75%), an additional 5.57% increase to the Group\u2019s existing equity in Jade, and three development prospects (Rosebank 20%, Cambo 70% at date of acquisition and Tornado 50%) to the existing
Group portfolio.
Taking into account the interim period cash flows generated by Siccar since the transaction effective date of 1 January 2022 and conventional working capital adjustments, the price payable at completion of the acquisition was
$1.015 billion. A risked contingent consideration of $102 million was recognised, resulting in a gain on bargain purchase of $704 million.
The contingent consideration arrangement on Siccar Point Energy depends on whether various milestones of the SPA are met as follows: redemption of acquired bond as at repayment date, 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 contingent consideration is subsequently revalued at each year-end date.
The gain on bargain purchase arising on the Siccar Point Energy transaction was principally as a result of recognising a deferred tax asset arising from tax losses of $1,334 million as allowed under IFRS 3 fair value accounting
for business combinations. The gain on bargain purchase of $704 million was credited to income in the year ended 31 December 2022.
On acquisition of Siccar Point Energy, the Group acquired a $200 million bond. On 28 July 2022 a Group of bondholders exercised their right to redeem and subsequently $166.4 million was paid to these bondholders. Subsequently,
in September 2022, notes totalling $25.6 million were bought back at a premium of 6% by the Group. The remaining notes totalling $8.0 million were redeemed on 12 October 2022 and there was no remaining balance at 31 December 2022.
Summit
On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Summit. The transaction added a further 2.1875% ownership of the Elgin Franklin field interest within the existing Group portfolio.
Taking into account the interim period cash flows generated by Summit since the transaction effective date of 1 January 2021, the $10 million deposit paid at signing of the transaction in February 2022 and conventional working capital
adjustments, the price payable at completion of the acquisition was $119 million and goodwill of $62 million was recognised. The goodwill recognised can be attributed to the increase in the Group\u2019s equity interest in the Elgin Franklin
field and the corresponding impact of EPL, which was announced between effective date and completion, on the fair values at acquisition.
There are no contingent consideration arrangements under the Sale and Purchase Agreement of the Summit assets.
No contingent liabilities have been acquired on the business combinations detailed above.
The fair values of the oil and gas assets and the intangible assets acquired have been determined using valuation techniques based on discounted cash flows using forward curve commodity prices and estimates of long-term commodity
prices reflective of market conditions at each completion date, a discount rate based on observable market data and cost and production profiles generally consistent with the proved and probable reserves acquired with each asset.
The decommissioning liabilities recognised have been estimated based on operator cost estimates with reference to observable market data.
", "dimensions": { "concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-494": { "value": "
18. Goodwill
2023 2022
US$\u2019000 US$\u2019000
Balance at 1 January
783,848
722,075
Additions (note 17)
\u2013
61,773
Balance at 31 December
783,848
783,848
The goodwill is not tax deductible on any of the acquisitions.
The goodwill on acquisition in the year to 31 December 2022 relates to the Summit acquisition, as detailed in note 17. Annual impairment tests were performed at both 31 December 2023 and 31 December 2022. These reviews were carried out on a fair value less cost of disposal basis using risk adjusted cash flow projections from the approved business plans including the same commodity prices, life of field cost profiles and production volumes used for impairment of oil and gas assets (see note 19), discounted at a post-tax discount rate of 10.3% (2022: 10.9%). Assumptions and estimates in the Group impairment models are detailed in note 3. An increase of 1% in the discount rate assumption would not result in a post-tax impairment of goodwill. Goodwill is monitored, and tested for impairment, at the operating segment level, being the North Sea (the entire Group portfolio of oil and gas assets). This is consistent with the operating segment view of the business which is presented to the Board and the Chief Decision Maker. The Group\u2019s activities are considered to be an individual operating segment due to the uniform nature of the Group\u2019s operations within a single geographical area, overseen by the same management and subject to the same regulations. The fair value estimate is categorised as level 3 in the fair value hierarchy.", "dimensions": { "concept": "ifrs-full:DisclosureOfIntangibleAssetsAndGoodwillExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-427": { "value": "18. Goodwill
2023 2022
US$\u2019000 US$\u2019000
Balance at 1 January
783,848
722,075
Additions (note 17)
\u2013
61,773
Balance at 31 December
783,848
783,848
The goodwill is not tax deductible on any of the acquisitions.
The goodwill on acquisition in the year to 31 December 2022 relates to the Summit acquisition, as detailed in note 17.
Annual impairment tests were performed at both 31 December 2023 and 31 December 2022. These reviews were carried out on a fair value less cost of disposal basis using risk adjusted cash flow projections from the approved
business plans including the same commodity prices, life of field cost profiles and production volumes used for impairment of oil and gas assets (see note 19), discounted at a post-tax discount rate of 10.3% (2022: 10.9%). Assumptions
and estimates in the Group impairment models are detailed in note 3. An increase of 1% in the discount rate assumption would not result in a post-tax impairment of goodwill. Goodwill is monitored, and tested for impairment, at the
operating segment level, being the North Sea (the entire Group portfolio of oil and gas assets). This is consistent with the operating segment view of the business which is presented to the Board and the Chief Decision Maker.
The Group\u2019s activities are considered to be an individual operating segment due to the uniform nature of the Group\u2019s operations within a single geographical area, overseen by the same management and subject to the same regulations.
The fair value estimate is categorised as level 3 in the fair value hierarchy.
", "dimensions": { "concept": "ifrs-full:DisclosureOfGoodwillExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-428": { "value": "
19. Impairment charge on oil and gas assets
2023 2022
US$\u2019000 US$\u2019000
D&P assets
(559,472)
(30,700)
E&E assets
\u2013
(1,867)
Other movements
1,536
\u2013
Contingent consideration reversal
\u2013
1,100
North Sea oil and gas assets
(557,936)
(31,467)
The impairment charge on D&P assets of $559.5 million (2022: $30.7 million) primarily relates to Alba of $141.3 million and the Greater Stella Area (GSA) of $373.2 million. The charge in 2022 reflected revisions in decommissioning
provisions, principally on fields that are no longer producing.
Estimated production volumes 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 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, as supported by third-party analysis, 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
Oil
10.3%
$85/bbl
$83/bbl
$87/bbl
$90/bbl
$93/bbl
Gas
10.3%
101p/therm
96p/therm
83p/therm
85p/therm
87p/therm
1
1. Post-2028 an annual 2% increase is applied to the price assumptions.
With all other assumptions held constant and supported by third-party analysis, a 20% decrease in the forecast revenues, illustrating lower commodity prices and/or production volumes, would result in an additional post-tax impairment
of PP&E of $22 million (2022: $13 million) at 31 December 2023. A 20% increase in forecast revenues would reduce the reported post-tax impairment by $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 and commodity prices for oil and gas due to changing consumer preferences and/or government regulations.
Utilising the Climate scenario\u2019s average oil price while maintaining all other parameters in line with the base case would result in an immaterial effect on additional post-tax impairment as at 31 December 2023.
To calculate the Climate Scenario average oil price, the Group utilised data from both the International Energy Agency (IEA) climate scenarios (NZ, STEPS, APS) and the World Business Council for Sustainable Development
(WBCSD) data catalogue. Management\u2019s base case assumption aligns substantially with climate-adjusted curves for gas and carbon emission prices; hence, no supplementary sensitivity analysis has been presented.
An impairment review was also carried out at the end of 2022 on the Group\u2019s producing assets with the main trigger being the implementation of the Energy Profits Levy (EPL) in the second half of 2022. The review demonstrated that
there was no requirement to impair any of the Group\u2019s producing assets. 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 10.9%.
The following assumptions, as supported by third-party analysis, were used at Q4 2022 in developing the cash flow model and applied over the expected life of the respective fields:
Post-tax Price assumptions (nominal)
discount rate
assumption
2023
2024
2025
2026
2027
Oil
10.9%
$89/bbl
$84/bbl
$83/bbl
$83/bbl
$83/bbl
Gas
10.9%
315p/therm
211p/therm
99p/therm
86p/therm
86p/therm
1
1. Post 2027 an annual 2% is applied to the price assumptions.
Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure, are derived from the approved business plans and third-party reports.
", "dimensions": { "concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-429": { "value": "
20. Borrowings
2023 2022
US$\u2019000 US$\u2019000
Current
Accrued interest costs on borrowings
(29,913)
\u2013
(29,913)
\u2013
Non-current
RBL facility
\u2013
(600,000)
Senior unsecured notes
(625,000)
(625,000)
bp unsecured loan
(100,000)
\u2013
Unamortised long-term bank fees
4,555
7,591
Unamortised long-term senior notes fees
2,207
3,678
Total debt
(718,238)
(1,213,731)
Accrued interest on borrowings has been re-classed in the current year from accruals (within trade and other payables) to borrowings, to reflect the current payable in respect of borrowings. The prior year equivalent of $21.7 million has
not been adjusted for this change as it is not material and remains within accruals for the year ended 31 December 2022.
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 221 to 223.
Reserves Based Lending (RBL) facility
During 2021, the Group completed a refinancing to amend and extend the RBL facility. The RBL commitment was approximately $1.225 billion with a maturity to 2026, and subject to interest at a reference rate of SOFR plus 3.5%.
At 31 December 2023, due to the NPV cap described in the covenants section below, the total availability was $725 million (2022: $925 million), of which none (2022: $600 million) was drawn down, leaving an amount of $725 million
(2022: $325 million) being available for drawdown. Subsequent to 31 December 2023, RBL liquidity increased from $725 million to $836 million.
Loan fees of $15.2 million relating to the RBL were capitalised and are being amortised over the term of the loan, $4.6 million (2022: $7.6 million) remains to be amortised as at 31 December 2023.
The RBL facility is secured by the assets of the guarantor members of the Group, such security including share pledges, floating charges and/or debentures. Total assets pledged as security at 31 December 2023 was $6,247 million
(2022: $6,760 million).
Senior notes
In 2021, the Group completed the refinancing of its senior unsecured notes with the issuance of $625 million 9% senior unsecured notes due July 2026 and repayment in full of the notes issued during 2019. Loan fees of $7.4 million
relating to the new senior notes were capitalised and are being amortised over the life of the loan, $2.2 million (2022: $3.7 million) remains to be amortised as at 31 December 2023.
Covenants in relation to these senior notes are detailed below.
On acquisition of Siccar Point Energy on 30 June 2022, the Group acquired their existing $200 million 9% senior unsecured notes due March 2026. The Group also acquired $5.8 million of accrued interest in relation to these senior notes.
On 1 August 2022, a settlement was made as a result of the exercise of the put option on the notes and a combined holding of $166.4 million exercised the put option. Subsequently, in September 2022, notes totalling $25.6 million were bought
back at a premium of 6% by the Group. The remaining notes totalling $8.0 million were fully redeemed on 12 October 2022.
bp facility
During the year to 31 December 2023, a new $100 million five-year facility was entered into with bp which is subject to an interest rate of SOFR plus a commercially agreed margin. The loan is unsecured, is due for repayment in 2028
and was fully drawn at 31 December 2023 (2022: $nil). Fees of $0.5 million were incurred on drawdown.
Optional project capital expenditure facility
During the year to 31 December, a carry arrangement of up to $150 million was entered into relating to a field development. The carry 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. The carry arrangement was undrawn at 31 December 2023.
Covenants
The Group is subject to financial and operating 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 and acquired senior notes. There are
no ongoing maintenance or financial covenant tests associated with the $625 million unsecured notes.
In addition to the below financial covenants, the Group is subject to restrictive covenants under the RBL facility and 2026 notes, restricting the Group, to, amongst other things: make certain payments (including, subject to certain
exceptions, dividends and other distributions), with respect to outstanding share capital; repay or redeem subordinated debt or share capital; create or incur certain liens; make certain acquisitions and investments or loans; sell, lease
or transfer certain assets, including shares of any of the Group\u2019s restricted subsidiaries; incur expenditure on exploration and appraisal activities in excess of approved levels; guarantee certain types of the Group\u2019s other indebtedness;
expand into unrelated businesses; merge or consolidate with other entities; or enter into certain transactions with affiliates.
The key financial covenants in the RBL are:
\u2022 The parent shall ensure that as at the end of each Relevant Period (starting with the Relevant Period ending on 30 November 2021) the ratio of adjusted net debt to adjusted EBITDAX shall be less than 3.5:1. \u2018Adjusted net debt\u2019
referred to is not an IFRS measure. The Company uses adjusted net debt as a measure to assess its financial position. Adjusted net debt comprises amounts outstanding under the Company\u2019s RBL facility, bp facility and senior notes,
less cash and cash equivalents;
\u2022 Total projected sources of funds must exceed the total projected uses of funds for the following 12-month period (or a longer period to first production from development, if applicable);
\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.
The Group was in compliance with all financial covenants of the RBL facility in all periods presented.
29. 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 \u2018other gains and losses\u2019 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 parent entity 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 2023 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through in hedge Total carrying
amortised cost profit or loss relationships amount
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Financial assets
Cash and cash equivalents
153,215
\u2013
\u2013
153,215
Trade and other receivables
330,351
\u2013
\u2013
330,351
Derivative financial instruments
\u2013
2,782
154,525
157,307
Financial liabilities
Borrowings
(748,151)
\u2013
\u2013
(748,151)
Trade and other payables
(343,279)
\u2013
\u2013
(343,279)
Lease liability
(20,559)
\u2013
\u2013
(20,559)
Contingent and deferred consideration
(63,979)
(296,390)
\u2013
(360,369)
Derivative financial instruments
\u2013
(10,373)
(3,335)
(13,708)
(845,193)
The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2022 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through in hedge Total carrying
amortised cost profit or loss relationships amount
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Financial assets
Cash and cash equivalents
253,822
\u2013
\u2013
253,822
Trade and other receivables
359,994
\u2013
\u2013
359,994
Derivative financial instruments
\u2013
7,125
164,924
172,049
Financial liabilities
Borrowings
(1,213,731)
\u2013
\u2013
(1,213,731)
Trade and other payables
(618,460)
\u2013
\u2013
(618,460)
Lease liability
(58,858)
\u2013
\u2013
(58,858)
Contingent and deferred consideration
(67,9
0 4)
(258,896)
\u2013
(326,800)
Derivative financial instruments
\u2013
(57,546)
(106,563)
(164,109)
(1,596,093)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2023:
Level 1 Level 2 Level 3 Total Fair Value
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Contingent consideration (note 25)
\u2013
(24,039)
(272,351)
(296,390)
Derivative financial instrument asset
\u2013
157,307
\u2013
157,307
Derivative financial instrument liability
\u2013
(13,708)
\u2013
(13,708)
Movements in level 3 financial instruments in the 12 months to 31 December 2023 were as follows:
US$\u2019000
At 1 January 2023
(223,246)
Additions
(26,872)
Cash settlement
\u2013
Accretion
(8,799)
Changes in fair value
(13,434)
At 31 December 2023
(272,351)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2022:
Level 1 Level 2 Level 3 Total Fair Value
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Contingent consideration (note 25)
\u2013
(35,650)
(223,246)
(258,896)
Derivative financial instrument asset
\u2013
172,049
\u2013
172,049
Derivative financial instrument liability
\u2013
(164,109)
\u2013
(164,109)
Movements in level 3 financial instruments in the 12 months to 31 December 2022 were as follows:
US$\u2019000
At 1 January 2022
(19,480)
Business combinations
(210,096)
Release of provision
1,100
Accretion
(5,208)
Changes in fair value
10,438
At 31 December 2022
(223,246)
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 $23.3 million (2022: $36.4 million). A 20% increase in the oil price would lead to an
increase in contingent consideration of $41.0 million (2022: $26.4 million).
The level three contingent consideration is valued based on the probability of the events occurring (\u201ctrigger events\u201d) as set out in note 17. The forecast cash flows in the event of the trigger event occurring are discounted at a rate of 4.6%
(2022: 4.25%).
The following table summarises the sensitivity of 20% change in probability of trigger event occurring and conditions being met for payment of contingent consideration, with all other variables held constant, of the Group\u2019s profit before
tax due to changes in the carrying value of level 3 financial instruments at the reporting date. The impact on equity is the same as the impact on profit before tax.
Change in probability
2023 2022
US$\u2019000 US$\u2019000
20% decrease in probability
97,119
87,0 8 0
20% increase in probability
(84,086)
(83,612)
The following table summarises the sensitivity of 1% decrease in discount rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting
date. The impact on equity is the same as the impact on profit before tax.
Change in discount rate
2023 2022
US$\u2019000 US$\u2019000
1% decrease in discount rate
(5,284)
(4,374)
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 2023 and
31 December 2022, 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 $748.2 million
(2022: $1,213.7 million) and the equivalent fair value is $781.4 million (2022: $1,257.9 million) per level 1 of the fair value hierarchy.
The table below presents the total gain on financial instruments that has been disclosed through the consolidated statement of profit or loss:
2023 2022
US$\u2019000 US$\u2019000
Revaluation of forex forward contracts
7,313
(28,172)
Revaluation of interest rate swaps
(6,488)
\u2013
Revaluation of commodity hedges
42,006
44,959
Total revaluation gain on financial instruments
42,831
16,787
Realised loss on forex forward contracts
(6,282)
\u2013
Realised gain on interest rate swaps
6,967
\u2013
Realised loss on commodity hedges
(457)
(16,215)
Total gain on financial instruments
43,059
572
Cash flow hedge reserve
The table below presents the movement in financial instruments that has been disclosed through the statement of comprehensive income relating to the cash flow hedge reserve:
Cash flow hedge reserve
2023 2022
US$\u2019000 US$\u2019000
At 1 January
16,710
(242,791)
Change in fair value of derivative instruments
358,141
(46,800)
Amounts recycled to revenue
(265,711)
501,513
Amounts recycled to finance costs
\u2013
(851)
Deferred tax on movement in year
(69,322)
(194,361)
Cash flow hedge reserve at 31 December
39,818
16,710
Cost of hedging reserve
The table below presents the movement in financial instruments that has been disclosed through the statement of comprehensive income relating to the cost of hedging reserve:
Cost of hedging reserve
2023 2022
US$\u2019000 US$\u2019000
At 1 January
3,275
(4,862)
Change in fair value of the intrinsic value of derivative instruments
(12,269)
(42,745)
Amounts recycled to revenue \u2013 oil put premiums
11,850
14,629
Amounts recycled to revenue \u2013 gas put premiums
3,590
42,347
Deferred tax on movement in year
(2,378)
(6,094)
Cost of hedging reserve at 31 December
4,068
3,275
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
12-month period under the RBL, the Group is required to hedge a minimum of 70% of volumes of net RBL entitlement production expected to be produced in the next 12 months, and 50% of volumes of net RBL entitlement produced
for the following 12 months on a best-effort basis.
The 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 below represents total commodity hedges in place at the 2022 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 23 \u2013 Jun 24
3,390,500
bbls
$70/bbl
Oil collars
Jan 23 \u2013 Dec 23
4,560,000
bbls
$68/bbl floor \u2013 $91/bbl ceiling
Gas swaps
Jan 23 \u2013 Jun 24
104,585,000
therms
188p/therm
Gas puts
Apr 23 \u2013 Sep 23
9,150,000
therms
220p/therm
Gas collars
Jan 23 \u2013 Mar 24
100,200,000
therms
244p/therm floor \u2013 479p/therm ceiling
The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at
the reporting date. The impact on equity is the same as the impact on profit before tax.
Change in realised commodity price
2023 2022
US$\u2019000 US$\u2019000
20% decrease in realised oil price
(177,151)
(246,914)
20% decrease in realised gas price
(146,794)
(330,285)
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 bp unsecured loan 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 material interest rate financial instruments in place at 31 December 2023.
The below represents interest rate financial instruments in place at the 2022 year end:
Derivative Term
Value
Rate
Interest rate swap (floating to fixed)
Jan 22 \u2013 Dec 23
$150 million
0.398%
The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities
at the reporting date.
Change in interest rate
2023 2022
US$\u2019000 US$\u2019000
Increase of 250 basis points
(22,370)
(11,126)
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 upon spot rate fluctuations from year-to-year.
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.
As at 31 December 2022 the Group had an average of \u00a35.5 million per quarter hedged at an average forward rate of $1.265:\u00a31 for the period January to December 2023. As at 31 December 2022 the Group had no open FX collars.
The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value
of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is not material.
Change in Sterling foreign exchange rate
2023 2022
US$\u2019000 US$\u2019000
10% weakening of Sterling against the US Dollar
(123,033)
(139,633)
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.
iv) Credit risk
The majority of the Group\u2019s trade and other receivables are with customers in the oil and gas industry 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. Oil production from Stella, Vorlich, Jade and Abigail fields is sold to ENI, Columba is sold to Repsol, Mariner to Equinor ASA, Pierce to Shell International Trading, and Captain, Alba, Cook, Forties (including
MonArb) and Schiehallion fields to BP Oil International. Forties fields (including MonArb), Stella, Vorlich, Jade and Abigail gas is sold to BP Gas Marketing. Cook gas is sold to Shell International Trading and Esso Exploration,
and Schiehallion to EnQuest.
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 2023, 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 2023 (31 December 2022: $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 2023, the Group\u2019s exposure is $nil (31 December 2022: $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 parent entity 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 2022 and 2023 substantially all accounts payable are current.
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 US$\u2019000 US$\u2019000 US\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(343,279)
\u2013
\u2013
(343,279)
(343,279)
Contingent and deferred consideration
\u2013
(101,669)
(248,388)
(44,508)
(394,565)
(360,369)
Lease liabilities
6.07%
(20,152)
(669)
\u2013
(20,821)
(20,559)
Borrowings
8.02%
(64,190)
(840,085)
\u2013
(904,275)
(748,151)
(529,290)
(1,089,142)
(44,508)
(1,662,940)
(1,472,358)
The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2022:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate US$\u2019000 US$\u2019000 US\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(618,460)
\u2013
\u2013
(618,460)
(618,460)
Contingent and deferred consideration
\u2013
(107,680)
(226,842)
(23,668)
(358,190)
(326,800)
Lease liabilities
6.38%
(44,257)
(17,439)
\u2013
(61,696)
(58,858)
Borrowings
8.85%
(98,250)
(1,474,528)
\u2013
(1,572,778)
(1,235,454)
(868,647)
(1,718,809)
(23,668)
(2,611,124)
(2,239,572)
The following table details the Group\u2019s liquidity analysis for its derivative financial instruments based on contractual maturities. The table has been drawn up based on the undiscounted net cash inflows and outflows on derivative
instruments that settle on a net basis, and the undiscounted gross inflows and outflows on those derivatives that require gross settlement. When the amount payable or receivable is not fixed, the amount disclosed has been determined
by reference to the projected interest rates as illustrated by the yield curves existing at the reporting date.
At 31 December 2023
Within
1 year Within 2 to 5 years Total
US$\u2019000 US$\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(2,290)
\u2013
(2,290)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(113,342)
\u2013
(113,342)
Foreign exchange collars \u2013 gross outflows
(155,071)
\u2013
(155,071)
(270,703)
\u2013
(270,703)
At 31 December 2022
Within
1 year Within 2 to 5 years Total
US$\u2019000 US$\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(51,654)
(15,402)
(67,056)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(83,529)
(107,235)
(190,764)
Foreign exchange collars \u2013 gross outflows
\u2013
\u2013
\u2013
(135,183)
(122,637)
(257, 820)
vi) Capital management
The Group\u2019s objectives when managing capital are to safeguard the Group\u2019s ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure
to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required.
The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates
eroding the Group\u2019s financial results.
30. Derivative financial instruments
The net carrying amount of each category of derivative is set out below:
2023 2022
US$\u2019000 US$\u2019000
Oil swaps \u2013 cash flow hedge
9,913
(28,685)
Oil swaps \u2013 non-cash flow hedge
\u2013
(15,027)
Oil collars \u2013 cash flow hedge
7,434
(21,983)
Gas swaps \u2013 cash flow hedge
47, 232
19,797
Gas swaps \u2013 non-cash flow hedge
(2,290)
(29,271)
Gas puts \u2013 cash flow hedge
\u2013
9,746
Gas collars \u2013 cash flow hedge
89,944
79,489
Interest rate swaps \u2013 non-cash flow hedge
637
7,125
FX forwards \u2013 non-cash flow hedge
(3,961)
(13,250)
FX collars \u2013 cash flow hedge
(3,335)
\u2013
FX collars \u2013 non-cash flow hedge
(1,975)
\u2013
143,599
7,941
2023 2022
Maturity analysis of derivative financial instruments US$\u2019000 US$\u2019000
Non-current assets
17,810
21,191
Current assets
139,497
150,858
Non-current liabilities
\u2013
(27,4 4 0)
Current liabilities
(13,708)
(136,668)
143,599
7,941
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 $113 million (2022: $179 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 2023 of $88 million (2022: $188 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 2023 and 2022.
Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2023 are detailed below:
Related amounts not set off in balance
Amount recognised in balance sheet sheet Net amount
$\u2019000 $\u2019000 $\u2019000
Derivative assets
157, 30 6
(4,436)
152,870
Derivative liabilities
(13,708)
4,436
(9,272)
Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2022 are detailed below:
Related amounts not set off in balance
Amount recognised in balance sheet sheet Net amount
$\u2019000 $\u2019000 $\u2019000
Derivative assets
172,049
(33,117)
138,932
Derivative liabilities
(164,109)
33,117
(130,992)
", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-459": { "value": "20. Borrowings
2023 2022
US$\u2019000 US$\u2019000
Current
Accrued interest costs on borrowings
(29,913)
\u2013
(29,913)
\u2013
Non-current
RBL facility
\u2013
(600,000)
Senior unsecured notes
(625,000)
(625,000)
bp unsecured loan
(100,000)
\u2013
Unamortised long-term bank fees
4,555
7,591
Unamortised long-term senior notes fees
2,207
3,678
Total debt
(718,238)
(1,213,731)
Accrued interest on borrowings has been re-classed in the current year from accruals (within trade and other payables) to borrowings, to reflect the current payable in respect of borrowings. The prior year equivalent of $21.7 million has not been adjusted for this change as it is not material and remains within accruals for the year ended 31 December 2022. 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 221 to 223. Reserves Based Lending (RBL) facility During 2021, the Group completed a refinancing to amend and extend the RBL facility. The RBL commitment was approximately $1.225 billion with a maturity to 2026, and subject to interest at a reference rate of SOFR plus 3.5%. At 31 December 2023, due to the NPV cap described in the covenants section below, the total availability was $725 million (2022: $925 million), of which none (2022: $600 million) was drawn down, leaving an amount of $725 million (2022: $325 million) being available for drawdown. Subsequent to 31 December 2023, RBL liquidity increased from $725 million to $836 million. Loan fees of $15.2 million relating to the RBL were capitalised and are being amortised over the term of the loan, $4.6 million (2022: $7.6 million) remains to be amortised as at 31 December 2023. The RBL facility is secured by the assets of the guarantor members of the Group, such security including share pledges, floating charges and/or debentures. Total assets pledged as security at 31 December 2023 was $6,247 million (2022: $6,760 million). Senior notes In 2021, the Group completed the refinancing of its senior unsecured notes with the issuance of $625 million 9% senior unsecured notes due July 2026 and repayment in full of the notes issued during 2019. Loan fees of $7.4 million relating to the new senior notes were capitalised and are being amortised over the life of the loan, $2.2 million (2022: $3.7 million) remains to be amortised as at 31 December 2023. Covenants in relation to these senior notes are detailed below. On acquisition of Siccar Point Energy on 30 June 2022, the Group acquired their existing $200 million 9% senior unsecured notes due March 2026. The Group also acquired $5.8 million of accrued interest in relation to these senior notes. On 1 August 2022, a settlement was made as a result of the exercise of the put option on the notes and a combined holding of $166.4 million exercised the put option. Subsequently, in September 2022, notes totalling $25.6 million were bought back at a premium of 6% by the Group. The remaining notes totalling $8.0 million were fully redeemed on 12 October 2022. bp facility During the year to 31 December 2023, a new $100 million five-year facility was entered into with bp which is subject to an interest rate of SOFR plus a commercially agreed margin. The loan is unsecured, is due for repayment in 2028 and was fully drawn at 31 December 2023 (2022: $nil). Fees of $0.5 million were incurred on drawdown. Optional project capital expenditure facility During the year to 31 December, a carry arrangement of up to $150 million was entered into relating to a field development. The carry 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. The carry arrangement was undrawn at 31 December 2023. Covenants The Group is subject to financial and operating 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 and acquired senior notes. There are no ongoing maintenance or financial covenant tests associated with the $625 million unsecured notes. In addition to the below financial covenants, the Group is subject to restrictive covenants under the RBL facility and 2026 notes, restricting the Group, to, amongst other things: make certain payments (including, subject to certain exceptions, dividends and other distributions), with respect to outstanding share capital; repay or redeem subordinated debt or share capital; create or incur certain liens; make certain acquisitions and investments or loans; sell, lease or transfer certain assets, including shares of any of the Group\u2019s restricted subsidiaries; incur expenditure on exploration and appraisal activities in excess of approved levels; guarantee certain types of the Group\u2019s other indebtedness; expand into unrelated businesses; merge or consolidate with other entities; or enter into certain transactions with affiliates. The key financial covenants in the RBL are: \u2022 The parent shall ensure that as at the end of each Relevant Period (starting with the Relevant Period ending on 30 November 2021) the ratio of adjusted net debt to adjusted EBITDAX shall be less than 3.5:1. \u2018Adjusted net debt\u2019 referred to is not an IFRS measure. The Company uses adjusted net debt as a measure to assess its financial position. Adjusted net debt comprises amounts outstanding under the Company\u2019s RBL facility, bp facility and senior notes, less cash and cash equivalents; \u2022 Total projected sources of funds must exceed the total projected uses of funds for the following 12-month period (or a longer period to first production from development, if applicable); \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. The Group was in compliance with all financial covenants of the RBL facility in all periods presented. ", "dimensions": { "concept": "ifrs-full:DisclosureOfBorrowingsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-430": { "value": "
21. Changes in liabilities arising from financing activities
Non-cash changes
Financing cash Fair value Other
1 January 2023 flows (i) Additions Imputed interest movements Amortisation Debt waiver movements (ii) 31 December 2023
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Borrowings (note 20)
1,213,731
(596,642)
\u2013
\u2013
\u2013
4,507
\u2013
126,554
748,150
Lease liabilities
58,858
(45,085)
3,603
\u2013
\u2013
\u2013
\u2013
3,183
20,559
Interest rate derivatives (note 29)
(7,125)
6,967
\u2013
\u2013
(479)
\u2013
\u2013
\u2013
(637)
Total liabilities from financing activities
1,265,464
(634,760)
3,603
\u2013
(479)
4,507
\u2013
129,737
768,072
Non-cash changes
Financing cash Fair value Other
1 January 2022 flows (i) Additions Imputed interest movements Amortisation Debt waiver movements (ii) 31 December 2022
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Borrowings (note 20)
954,616
50,000
200,000
\u2013
\u2013
4,508
\u2013
\u2013
1,213,731
Parent Company debt (note 31)
437,076
(273,055)
\u2013
17,924
\u2013
\u2013
(181,945)
\u2013
\u2013
Lease liabilities
3,489
(38,200)
\u2013
\u2013
\u2013
\u2013
\u2013
93,569
58,858
Interest rate derivatives (note 29)
(133)
851
\u2013
\u2013
(7,8 43)
\u2013
\u2013
\u2013
(7,125)
Total liabilities from financing activities
1,395,048
(260,404)
200,000
17, 924
(7,843)
4,508
(181,945)
98,176
1,265,464
(i) The cash flows from borrowings, Parent Company debt, lease liabilities and interest rate derivatives make up the net amount of proceeds from borrowings and repayments of borrowings in the cash flow statement.
(ii) Other movements include interest accruals and new liabilities in the year.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-460": { "value": "21. Changes in liabilities arising from financing activities
Non-cash changes
Financing cash Fair value Other
1 January 2023 flows (i) Additions Imputed interest movements Amortisation Debt waiver movements (ii) 31 December 2023
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Borrowings (note 20)
1,213,731
(596,642)
\u2013
\u2013
\u2013
4,507
\u2013
126,554
748,150
Lease liabilities
58,858
(45,085)
3,603
\u2013
\u2013
\u2013
\u2013
3,183
20,559
Interest rate derivatives (note 29)
(7,125)
6,967
\u2013
\u2013
(479)
\u2013
\u2013
\u2013
(637)
Total liabilities from financing activities
1,265,464
(634,760)
3,603
\u2013
(479)
4,507
\u2013
129,737
768,072
Non-cash changes
Financing cash Fair value Other
1 January 2022 flows (i) Additions Imputed interest movements Amortisation Debt waiver movements (ii) 31 December 2022
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Borrowings (note 20)
954,616
50,000
200,000
\u2013
\u2013
4,508
\u2013
\u2013
1,213,731
Parent Company debt (note 31)
437,076
(273,055)
\u2013
17,924
\u2013
\u2013
(181,945)
\u2013
\u2013
Lease liabilities
3,489
(38,200)
\u2013
\u2013
\u2013
\u2013
\u2013
93,569
58,858
Interest rate derivatives (note 29)
(133)
851
\u2013
\u2013
(7,8 43)
\u2013
\u2013
\u2013
(7,125)
Total liabilities from financing activities
1,395,048
(260,404)
200,000
17, 924
(7,843)
4,508
(181,945)
98,176
1,265,464
(i) The cash flows from borrowings, Parent Company debt, lease liabilities and interest rate derivatives make up the net amount of proceeds from borrowings and repayments of borrowings in the cash flow statement. (ii) Other movements include interest accruals and new liabilities in the year.", "dimensions": { "concept": "ifrs-full:DisclosureOfReconciliationOfLiabilitiesArisingFromFinancingActivitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-431": { "value": "
22. Trade and other payables
2023 2022
US$\u2019000 US$\u2019000
Trade payables
(34,559)
(14,917)
Hydrocarbon amounts owed to joint operations/overlift
(72,486)
(124,365)
Other payables
(68,034)
(185,720)
Accruals
(254,781)
(299,604)
Deferred income
(48,747)
(86,806)
(478,607)
(711,412)
The Directors consider the carrying values of trade and other payables to approximate the fair value. Other payables mainly comprises amounts owed due to production adjustments and amounts owed to joint operations partners.
Deferred income represents receipts in advance of deliveries to customers. The prior year deferred income was recognised in revenue in the current year.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-502": { "value": "22. Trade and other payables
2023 2022
US$\u2019000 US$\u2019000
Trade payables
(34,559)
(14,917)
Hydrocarbon amounts owed to joint operations/overlift
(72,486)
(124,365)
Other payables
(68,034)
(185,720)
Accruals
(254,781)
(299,604)
Deferred income
(48,747)
(86,806)
(478,607)
(711,412)
The Directors consider the carrying values of trade and other payables to approximate the fair value. Other payables mainly comprises amounts owed due to production adjustments and amounts owed to joint operations partners. Deferred income represents receipts in advance of deliveries to customers. The prior year deferred income was recognised in revenue in the current year. 23. Decommissioning liabilities
2023 2022
US$\u2019000 US$\u2019000
Balance at 1 January
(1,720,540)
(1,641,489)
Business combination additions
\u2013
(390,530)
Accretion
(74,621)
(52,592)
Additions and revisions to estimates
(160,069)
298,564
Decommissioning provision utilised
95,552
65,507
Balance at 31 December
(1,859,678)
(1,720,540)
Current
Balance at 1 January
(146,829)
(94,640)
Balance at 31 December
(107,026)
(146,829)
Non-current
Balance at 1 January
(1,573,711)
(1,546,849)
Balance at 31 December
(1,752,652)
(1,573,711)
Additions and revisions to estimates comprise $157,224k (2022: $(278,398)k) of development and production assets and $2,845k (2022: $(20,166)k) of exploration and evaluation assets. 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. The Group uses a nominal discount rate of 4.60% (31 December 2022: 4.25%) and an inflation rate of 2.0% (31 December 2022: 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 2023 and 2022 were due to changes in both cost estimates and discount rate assumptions. The estimated 2024 decommissioning spend of $107 million (2022: estimated 2023 decommissioning spend of $147 million) has been treated as a current liability as at 31 December 2023. Although the Group currently expects to incur decommissioning costs over the next 40 years, it is estimated that approximately 47% of the decommissioning liability relates to assets which are expected to cease production in the next five years and which includes spend for assets that will be reimbursed (see note 11 for further details). 27. Taxation
2023 2022
US$\u2019000 US$\u2019000
Current tax
Current corporation tax charge
(39,308)
(54,557)
Current EPL tax charge
(333,425)
(131,389)
Current corporation tax (charge)/credit \u2013 prior year
(17,426)
1,839
Total current tax charge
(390,159)
(184,107)
Deferred tax
Adjustment in respect of prior period
6,370
(641)
Group tax credit/(charge) in consolidated statement of profit or loss
227,360
(1,013,817)
Group tax charge in consolidated statement of other comprehensive income
(71,700)
(200,455)
Total deferred tax credit/(charge)
162,030
(1,214,913)
Deferred Petroleum Revenue Tax
Deferred PRT credit/(charge) in statement of profit or loss
70,037
(10,432)
Total tax charge through consolidated statement of profit or loss
(86,392)
(1,208,997)
The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:
2023 2022
US$\u2019000 US$\u2019000
Accounting profit before tax
302,027
2,240,529
At tax rate of 40% (2022: 40%)
(120,811)
(896,211)
Non-deductible expense
(34,578)
(53,548)
Recognition of non-taxable gain on bargain purchase
\u2013
534,069
Financing costs not allowed for SCT
(704)
(1,958)
Ring Fence Expenditure Supplement
102,866
155,113
Deferred tax effect of investment allowance
56,930
(20,615)
Prior year adjustment
(11,673)
1,198
Deferred PRT net of corporation tax
42,022
(6,259)
Deferred tax on EPL
215,910
(766,489)
Current tax on EPL
(333,425)
(131,389)
Prior year adjustments on acquired entities
\u2013
(3,165)
Share-based payments
1,945
\u2013
Unrecognised tax losses
(4,874)
(19,743)
Total tax charge recorded in the consolidated statement of profit or loss
(86,392)
(1,208,997)
The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in both 2023 and 2022, prior to the introduction of the EPL, was 40% (2022: 40%) consisting of a Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include 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. The credit arising in 2023 of $42.0 million was principally due the impairment of the Alba field due to forecast future production volumes. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK however adjustments to recognised deferred PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The EPL was enacted in July 2022 with effect from 26 May 2022, at a headline rate of 25% which increased the effective UK Ring Fenced oil and gas rate to 65% until 2025, resulting in additional current and deferred tax charges in the year to 31 December 2022. Further changes to the EPL were announced on 17 November 2022 and enacted in December 2022 whereby the Levy was increased to 35% from 1 January 2023 until 31 March 2028, increasing the effective UK Ring Fenced oil and gas tax rate to 75% resulting in an additional deferred tax charge during the year to 31 December 2022. Deferred tax at 31 December relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Deferred corporation tax liability
(1,944,941)
(2,258,813)
Deferred corporation tax asset
2,480,921
2,629,548
Deferred PRT asset
91,759
21,721
Net deferred tax asset
627,738
392,456
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. Non-oil and gas losses of $251 million (2022: $156 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses. The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
392,456
220,918
Profit or loss credit/(charge)
303,767
(1,024,889)
Other comprehensive income charge
(71,700)
(200,455)
Deferred tax on decommissioning reimbursements (note 11)
3,214
\u2013
Business combinations (note 17)
\u2013
1,396,882
At 31 December
627,738
392,456
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Accelerated capital allowances
438,359
(490,246)
Tax losses
(216,937)
(386,819)
Decommissioning provision
52,440
(124,598)
Deferred PRT
(28,015)
4,173
Hedging
(101,744)
(226,040)
Share schemes
3,978
\u2013
Investment allowances
13,950
8,617
162,030
(1,214,913)
Gross deferred corporation tax liabilities
Deferred
corporation tax on Accelerated tax
Hedges deferred PRT depreciation Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
(12,861)
(675,279)
(688,140)
Prior year adjustment
\u2013
\u2013
(4,347)
(4,347)
Reclassification of decommissioning asset
\u2013
\u2013
(436,771)
(436,771)
Business combinations
\u2013
\u2013
(647,743)
(6 47,74
3)
Origination and reversal of temporary differences
\u2013
4,173
(485,985)
(481,812)
At 31 December 2022 and 1 January 2023
\u2013
(8,688)
(2,250,125)
(2,258,813)
Reclass to deferred corporation tax assets
(8,678)
\u2013
\u2013
(8,678)
Prior year adjustment
2,721
\u2013
8,307
11,028
Origination and reversal of temporary differences
(101,744)
(28,015)
441,281
311,522
At 31 December 2023
(107,701)
(36,703)
(1,800,537)
(1,944,941)
Gross deferred corporation tax assets
Decommissioning
Share schemes provision Tax losses Hedges Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
197,666
500,282
178,956
876,904
Prior year adjustment
\u2013
\u2013
3,706
\u2013
3,706
Reclassification of decommissioning asset
\u2013
436,772
\u2013
\u2013
436,772
Business combinations
\u2013
156,212
1,858,706
38,406
2,053,324
Origination and reversal of temporary differences
\u2013
(124,598)
(390,520)
(226,040)
(741,158)
At 31 December 2022 and 1 January 2023
\u2013
666,052
1,972,174
(8,678)
2,629,548
Reclass from deferred corporation tax liabilities
\u2013
\u2013
\u2013
8,678
8,678
Prior year adjustment
177
\u2013
(4,989)
\u2013
(4,812)
Origination and reversal of temporary differences
3,802
55,654
(211,949)
\u2013
(152,493)
At 31 December 2023
3,979
721,706
1,755,236
\u2013
2,480,921
Total
Deferred PRT asset US$\u2019000
At 1 January 2022
32,154
Origination and reversal of temporary differences
(10,433)
At 31 December 2022 and 1 January 2023
21,721
Origination and reversal of temporary differences
70,037
At 31 December 2023
91,758
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2023 of $536 million and $92 million respectively (2022: $371 million and $21 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 a restructuring exercise to move certain assets between Group entities which has 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 upon 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. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million. On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective for all accounting periods starting on or after 31 December 2023. The Group does not anticipate that the adoption of this will have a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate. The Group has applied the exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and therefore there is no impact on the tax values reported.", "dimensions": { "concept": "ifrs-full:DisclosureOfOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-480": { "value": "22. Trade and other payables
2023 2022
US$\u2019000 US$\u2019000
Trade payables
(34,559)
(14,917)
Hydrocarbon amounts owed to joint operations/overlift
(72,486)
(124,365)
Other payables
(68,034)
(185,720)
Accruals
(254,781)
(299,604)
Deferred income
(48,747)
(86,806)
(478,607)
(711,412)
The Directors consider the carrying values of trade and other payables to approximate the fair value. Other payables mainly comprises amounts owed due to production adjustments and amounts owed to joint operations partners. Deferred income represents receipts in advance of deliveries to customers. The prior year deferred income was recognised in revenue in the current year. ", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredIncomeExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-461": { "value": "22. Trade and other payables
2023 2022
US$\u2019000 US$\u2019000
Trade payables
(34,559)
(14,917)
Hydrocarbon amounts owed to joint operations/overlift
(72,486)
(124,365)
Other payables
(68,034)
(185,720)
Accruals
(254,781)
(299,604)
Deferred income
(48,747)
(86,806)
(478,607)
(711,412)
The Directors consider the carrying values of trade and other payables to approximate the fair value. Other payables mainly comprises amounts owed due to production adjustments and amounts owed to joint operations partners. Deferred income represents receipts in advance of deliveries to customers. The prior year deferred income was recognised in revenue in the current year. ", "dimensions": { "concept": "ifrs-full:DisclosureOfAccruedExpensesAndOtherLiabilitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-432": { "value": "23. Decommissioning liabilities
2023 2022
US$\u2019000 US$\u2019000
Balance at 1 January
(1,720,540)
(1,641,489)
Business combination additions
\u2013
(390,530)
Accretion
(74,621)
(52,592)
Additions and revisions to estimates
(160,069)
298,564
Decommissioning provision utilised
95,552
65,507
Balance at 31 December
(1,859,678)
(1,720,540)
Current
Balance at 1 January
(146,829)
(94,640)
Balance at 31 December
(107,026)
(146,829)
Non-current
Balance at 1 January
(1,573,711)
(1,546,849)
Balance at 31 December
(1,752,652)
(1,573,711)
Additions and revisions to estimates comprise $157,224k (2022: $(278,398)k) of development and production assets and $2,845k (2022: $(20,166)k) of exploration and evaluation assets. 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. The Group uses a nominal discount rate of 4.60% (31 December 2022: 4.25%) and an inflation rate of 2.0% (31 December 2022: 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 2023 and 2022 were due to changes in both cost estimates and discount rate assumptions. The estimated 2024 decommissioning spend of $107 million (2022: estimated 2023 decommissioning spend of $147 million) has been treated as a current liability as at 31 December 2023. Although the Group currently expects to incur decommissioning costs over the next 40 years, it is estimated that approximately 47% of the decommissioning liability relates to assets which are expected to cease production in the next five years and which includes spend for assets that will be reimbursed (see note 11 for further details). ", "dimensions": { "concept": "ithacaenergyplc:DisclosureOfDecommissioningLiabilities", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-433": { "value": "
24. Lease liabilities
Current
2023 2022
US$\u2019000 US$\u2019000
Lease liabilities
(19,898)
(41,637)
Non-current
2023 2022
US$\u2019000 US$\u2019000
Lease liabilities
(660)
(17,221)
The following table sets out a maturity analysis of lease payments, showing the undiscounted lease payments to be paid after the reporting date. All lease liabilities are fully payable within two years from 31 December 2023.
2023 2022
US$\u2019000 US$\u2019000
Less than one year
(20,152)
(44,257)
One to two years
(669)
(17,439)
Total undiscounted lease payments
(20,821)
(61,696)
Future finance charges and other adjustments
263
2,838
Lease liabilities in the financial statements
(20,558)
(58,858)
2023 2022
US$\u2019000 US$\u2019000
At 1 January
(58,858)
(3,489)
Additions
(3,603)
(89,717)
Interest
(3,183)
(3,852)
Payments
45,086
38,200
At 31 December
(20,558)
(58,858)
Current
(19,898)
(41,637)
Non-current
(660)
(17,221)
(20,558)
(58,858)
The additions in the year to 31 December 2023 relate to modifications of the Captain Emergency Response and Recovery Vehicle lease.
The addition in the year to 31 December 2022 relates to the Pioneer rig lease currently utilised on the Captain EOR project. The incremental borrowing rate applied to the lease is 6.07%.
If the Company were to terminate the use of the Pioneer rig early then termination fees would apply, escalating to 75% of total expected costs if within one month prior to commencement date of planned works. Remuneration for work
performed up to the date of termination, together with costs relating to demobilisation of the drilling unit to the demobilisation port would also be due.
Amounts recognised in profit and loss related to leases is detailed in notes 6 and 9.
", "dimensions": { "concept": "ifrs-full:DisclosureOfLeasesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-434": { "value": "
25. Contingent and deferred consideration
Current
2023 2022
US$\u2019000 US$\u2019000
Contingent consideration
(101,669)
(101,559)
Petrofac deferred consideration
\u2013
(6,121)
(101,669)
(107,680)
Non-current
2023 2022
US$\u2019000 US$\u2019000
Contingent consideration
(194,721)
(157,337)
MOGL deferred consideration
(63,979)
(61,783)
(258,700)
(219,120)
2023 2022
US$\u2019000 US$\u2019000
Cash flows relating to contingent and deferred considerations
(13,567)
(66,132)
Movement in contingent consideration is as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
(258,896)
(19,480)
Business combinations (note 17)
\u2013
(241,431)
Addition
(26,872)
\u2013
Payments made
7, 20 0
11,040
Reversal
\u2013
1,100
Accretion
(9,814)
(5,830)
Changes in fair value
(8,008)
(4,295)
At 31 December
(296,390)
(258,896)
Movement in deferred consideration consideration is as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
(67,90
4)
(55,610)
Business combinations (note 17)
\u2013
(63,415)
Payments made
6,367
55,156
Accretion
(2,442)
(4,035)
At 31 December
(63,979)
(67,904)
Cash outflows in the year ended 31 December 2023 of $13.6 million (2022: $66.1 million) are in relation to the consideration payable on Petrofac GSA transaction and quarterly payments in consideration to the MOGL and Siccar oil
price triggers.
MOGL
During the year ended 31 December 2022 the Group acquired MOGL which included elements of consideration that are payable upon certain events occurring and contingent considerations have been recognised to reflect this.
Further details regarding the acquisition and the related contingent terms are set out in note 17. The carrying amount at 31 December 2023, discounted at 4.6% was $111 million (2022: $128 million using a discount rate of 4.25%).
The total undiscounted potential consideration as at 31 December 2023 is $230 million (2022: $241 million).
The MOGL deferred consideration of $64 million (2022: $62 million) relates to completion of the MOGL transaction in February 2022. It is payable on 1 July 2025 and is discounted to reflect the time value of money.
Siccar
During the year ended 31 December 2022 the Group acquired Siccar Point Energy which included elements of consideration that are payable upon certain events occurring and contingent considerations have been recognised to
reflect this. Further details regarding the acquisition and the related contingent terms are set out in note 17. The carrying amount at 31 December 2023, discounted at 4.6% was $130 million (2022: $102 million using a discount rate of
4.25%). The total undiscounted potential consideration as at 31 December 2023 is $362 million (2022: $362 million). As a result of the Rosebank field obtaining FDP approval during 2023, the carrying amount at 31 December 2023
has been increased.
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 2023 was $12.7 million (2022: $nil).
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 2023
was $14.2 million (2022: $nil).
A further $3.0 million (2022: $6.4 million) relates to Yeoman/Marigold, with a remaining unrisked payment of $11.0 million (2022: $11.0 million) contingent on achieving FDP and a further $6.0 million (2022: $6.0 million) unrisked
on certain production criteria being met.
During the year ended 31 December 2023, further consideration of $5.7 million (2022: $6.4 million) was recognised as an additional payable due to changes in the variables in the calculation of the liability, resulting in $25.6 million
(2022: $19.9 million) liability on Strathspey in accordance with the Sale and Purchase Agreement with Chevron.
Revaluation of contingent consideration in the year to 31 December 2023 resulted in an increase of $8.0 million (2022: increase of $4.3 million).
", "dimensions": { "concept": "ithacaenergyplc:DisclosureOfContingentAndDeferredConsideration", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-435": { "value": "
26. Reserves
(a) Issued share capital
The issued share capital is as follows:
Number of Amount
common shares US$\u2019000
At 31 December 2022
1,006,564,976
11,445
At 31 December 2023
1,014,372,281
11,540
On 5 October 2023, 7,807,305 ordinary shares of \u00a30.01 each were issue to the Ithaca Energy plc Employee Benefit Trust (EBT) to satisfy the exercise of share options during the year and in future years.
On 26 October 2022 the Company undertook a share capital reduction whereby 114,000,000 issued A ordinary shares of $1.00 each were cancelled and extinguished. In addition on this date the share premium account as at 31 December
2021 of $634,658,000 was cancelled. A number of further steps followed in preparation for the IPO including the conversion of $1.00 shares to \u00a30.88 shares, the conversion of \u00a30.88 shares to \u00a30.01 shares, the issue of bonus shares principally
to existing shareholders and the issue of 105,000,000 new shares on the IPO. As a result the issued share capital of the Company immediately after the IPO was 1,005,162,217 ordinary shares of \u00a30.01 each.
A reconciliation of the opening to closing number of shares in the year to 31 December 2022 is set out below:
Number of shares
A ordinary
B1 ordinary
B2 ordinary
Ordinary
Total
A ordinary shares of $1.00 each at 1 January 2022
1,001
\u2013
\u2013
\u2013
1,001
Issue of new $0.01 B1 shares and $0.01 B2 shares
\u2013
100
100
\u2013
200
Issue of new $1.00 A ordinary shares
114,000,000
\u2013
\u2013
\u2013
114,000,000
Cancellation of $1.00 A ordinary shares relating to capital reduction
(114,000,000)
\u2013
\u2013
\u2013
(114,000,000)
Conversion of $1.00 A ordinary shares, $0.01 B1 share and 0.01 B2 share to \u00a30.01 A ordinary shares
87,087
(12)
(12)
\u2013
87,063
Bonus issue of new \u00a30.01 A shares
898,131,843
\u2013
\u2013
\u2013
898,131,843
Bonus issue of new \u00a30.01 B1 shares
\u2013
1,401,670
\u2013
\u2013
1,401,670
Bonus issue of new \u00a30.01 B2 shares
\u2013
\u2013
420,440
\u2013
420,440
Conversion of \u00a3 0.01 A ordinary shares, \u00a30.01 B1 shares and \u00a30.01 B2 shares to \u00a30.01 ordinary shares
(898,219,931)
(1,401,758)
(420,528)
900,042,217
\u2013
Bonus issues of \u00a30.01 ordinary shares
\u2013
\u2013
\u2013
120,000
120,000
Issue of new \u00a30.01 ordinary shares on IPO
\u2013
\u2013
\u2013
105,000,000
105,000,000
Issue of new \u00a30.01 ordinary shares on exercise of share options
\u2013
\u2013
\u2013
1,402,759
1,402,759
Ordinary shares of \u00a30.01 each at 31 December 2022
\u2013
\u2013
\u2013
1,006,564,976
1,006,564,976
(b) Share premium
2023 2022
US$\u2019000 US$\u2019000
At 1 January
293,712
634,658
Share premium cancellation
\u2013
(634,658)
Additions
15,133
293,712
At 31 December
308,845
293,712
The share premium account represents the cumulative difference between the market share price and the nominal share value on the issuance of new ordinary shares multiplied by the number of shares issued. Additions during 2023 represent the difference between the nominal value per share of \u00a30.01 and the closing share price on the day before the shares were issued to the EBT multiplied by the number of shares. During 2022, the additions represent the difference between the nominal value per share of \u00a30.01 and IPO price of \u00a32.50 per share multiplied by the number of shares issued (net of share issues expenses). (c) Capital contribution reserve
2023 2022
US$\u2019000 US$\u2019000
At 1 January
181,945
114,000
Capital reduction
\u2013
(114,000)
Addition
\u2013
181,945
At 31 December
181,945
181,945
During the year to 31 December 2022, the Company settled outstanding loan liabilities (including interest) of DKL Energy Limited (DKLE) out of IPO proceeds. As per the terms of the confirmation letter dated 29 November 2022 signed between DKLE and the Company, DKLE unconditionally and irrevocably released and forever discharged Ithaca Energy plc from any and all liabilities to the DKLE in respect of or in connection with the Capital and Subordinated loan note agreements. The remaining loan balance of $181.9 million has been capitalised as Capital Contribution Reserve as per the requirements of IFRS 9. (d) Own shares
2023 2022
US$\u2019000 US$\u2019000
At 31 December
(12,412)
\u2013
Own shares comprise shares held in the Ithaca Energy plc EBT which are being used to satisfy the exercise of employee share options. During the year, 7,807,305 ordinary shares of \u00a30.01 each were issued to the EBT and 1,443,561 ordinary shares were used to satisfy the exercise of share options. In addition, 1,822,286 ordinary shares of \u00a30.01 each waived under the MEP (see note 32) were transferred into the EBT during the year. As a result, the EBT held 8,186,030 ordinary shares of \u00a30.01 each at 31 December 2023. (e) Share-based payment reserve (note 32)
2023 2022
US$\u2019000 US$\u2019000
At 31 December
15,494
4,920
The share-based payment reserve represents the cumulative charge for share options, as described in note 32, less the cumulative cost of share option exercises.", "dimensions": { "concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-462": { "value": "(a) Issued share capital The issued share capital is as follows:
Number of Amount
common shares US$\u2019000
At 31 December 2022
1,006,564,976
11,445
At 31 December 2023
1,014,372,281
11,540
On 5 October 2023, 7,807,305 ordinary shares of \u00a30.01 each were issue to the Ithaca Energy plc Employee Benefit Trust (EBT) to satisfy the exercise of share options during the year and in future years. On 26 October 2022 the Company undertook a share capital reduction whereby 114,000,000 issued A ordinary shares of $1.00 each were cancelled and extinguished. In addition on this date the share premium account as at 31 December 2021 of $634,658,000 was cancelled. A number of further steps followed in preparation for the IPO including the conversion of $1.00 shares to \u00a30.88 shares, the conversion of \u00a30.88 shares to \u00a30.01 shares, the issue of bonus shares principally to existing shareholders and the issue of 105,000,000 new shares on the IPO. As a result the issued share capital of the Company immediately after the IPO was 1,005,162,217 ordinary shares of \u00a30.01 each. A reconciliation of the opening to closing number of shares in the year to 31 December 2022 is set out below:
Number of shares
A ordinary
B1 ordinary
B2 ordinary
Ordinary
Total
A ordinary shares of $1.00 each at 1 January 2022
1,001
\u2013
\u2013
\u2013
1,001
Issue of new $0.01 B1 shares and $0.01 B2 shares
\u2013
100
100
\u2013
200
Issue of new $1.00 A ordinary shares
114,000,000
\u2013
\u2013
\u2013
114,000,000
Cancellation of $1.00 A ordinary shares relating to capital reduction
(114,000,000)
\u2013
\u2013
\u2013
(114,000,000)
Conversion of $1.00 A ordinary shares, $0.01 B1 share and 0.01 B2 share to \u00a30.01 A ordinary shares
87,087
(12)
(12)
\u2013
87,063
Bonus issue of new \u00a30.01 A shares
898,131,843
\u2013
\u2013
\u2013
898,131,843
Bonus issue of new \u00a30.01 B1 shares
\u2013
1,401,670
\u2013
\u2013
1,401,670
Bonus issue of new \u00a30.01 B2 shares
\u2013
\u2013
420,440
\u2013
420,440
Conversion of \u00a3 0.01 A ordinary shares, \u00a30.01 B1 shares and \u00a30.01 B2 shares to \u00a30.01 ordinary shares
(898,219,931)
(1,401,758)
(420,528)
900,042,217
\u2013
Bonus issues of \u00a30.01 ordinary shares
\u2013
\u2013
\u2013
120,000
120,000
Issue of new \u00a30.01 ordinary shares on IPO
\u2013
\u2013
\u2013
105,000,000
105,000,000
Issue of new \u00a30.01 ordinary shares on exercise of share options
\u2013
\u2013
\u2013
1,402,759
1,402,759
Ordinary shares of \u00a30.01 each at 31 December 2022
\u2013
\u2013
\u2013
1,006,564,976
1,006,564,976
", "dimensions": { "concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-464": { "value": "
(b) Share premium
2023 2022
US$\u2019000 US$\u2019000
At 1 January
293,712
634,658
Share premium cancellation
\u2013
(634,658)
Additions
15,133
293,712
At 31 December
308,845
293,712
The share premium account represents the cumulative difference between the market share price and the nominal share value on the issuance of new ordinary shares multiplied by the number of shares issued.
Additions during 2023 represent the difference between the nominal value per share of \u00a30.01 and the closing share price on the day before the shares were issued to the EBT multiplied by the number of shares.
During 2022, the additions represent the difference between the nominal value per share of \u00a30.01 and IPO price of \u00a32.50 per share multiplied by the number of shares issued (net of share issues expenses).
(c) Capital contribution reserve
2023 2022
US$\u2019000 US$\u2019000
At 1 January
181,945
114,000
Capital reduction
\u2013
(114,000)
Addition
\u2013
181,945
At 31 December
181,945
181,945
During the year to 31 December 2022, the Company settled outstanding loan liabilities (including interest) of DKL Energy Limited (DKLE) out of IPO proceeds. As per the terms of the confirmation letter dated 29 November 2022
signed between DKLE and the Company, DKLE unconditionally and irrevocably released and forever discharged Ithaca Energy plc from any and all liabilities to the DKLE in respect of or in connection with the Capital and Subordinated
loan note agreements. The remaining loan balance of $181.9 million has been capitalised as Capital Contribution Reserve as per the requirements of IFRS 9.
", "dimensions": { "concept": "ifrs-full:DisclosureOfReservesAndOtherEquityInterestExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-463": { "value": "
(d) Own shares
2023 2022
US$\u2019000 US$\u2019000
At 31 December
(12,412)
\u2013
Own shares comprise shares held in the Ithaca Energy plc EBT which are being used to satisfy the exercise of employee share options. During the year, 7,807,305 ordinary shares of \u00a30.01 each were issued to the EBT and 1,443,561
ordinary shares were used to satisfy the exercise of share options. In addition, 1,822,286 ordinary shares of \u00a30.01 each waived under the MEP (see note 32) were transferred into the EBT during the year. As a result, the EBT held
8,186,030 ordinary shares of \u00a30.01 each at 31 December 2023.
", "dimensions": { "concept": "ifrs-full:DisclosureOfTreasurySharesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-436": { "value": "
27. Taxation
2023 2022
US$\u2019000 US$\u2019000
Current tax
Current corporation tax charge
(39,308)
(54,557)
Current EPL tax charge
(333,425)
(131,389)
Current corporation tax (charge)/credit \u2013 prior year
(17,426)
1,839
Total current tax charge
(390,159)
(184,107)
Deferred tax
Adjustment in respect of prior period
6,370
(641)
Group tax credit/(charge) in consolidated statement of profit or loss
227,360
(1,013,817)
Group tax charge in consolidated statement of other comprehensive income
(71,700)
(200,455)
Total deferred tax credit/(charge)
162,030
(1,214,913)
Deferred Petroleum Revenue Tax
Deferred PRT credit/(charge) in statement of profit or loss
70,037
(10,432)
Total tax charge through consolidated statement of profit or loss
(86,392)
(1,208,997)
The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:
2023 2022
US$\u2019000 US$\u2019000
Accounting profit before tax
302,027
2,240,529
At tax rate of 40% (2022: 40%)
(120,811)
(896,211)
Non-deductible expense
(34,578)
(53,548)
Recognition of non-taxable gain on bargain purchase
\u2013
534,069
Financing costs not allowed for SCT
(704)
(1,958)
Ring Fence Expenditure Supplement
102,866
155,113
Deferred tax effect of investment allowance
56,930
(20,615)
Prior year adjustment
(11,673)
1,198
Deferred PRT net of corporation tax
42,022
(6,259)
Deferred tax on EPL
215,910
(766,489)
Current tax on EPL
(333,425)
(131,389)
Prior year adjustments on acquired entities
\u2013
(3,165)
Share-based payments
1,945
\u2013
Unrecognised tax losses
(4,874)
(19,743)
Total tax charge recorded in the consolidated statement of profit or loss
(86,392)
(1,208,997)
The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in both 2023 and 2022, prior to the introduction of the EPL, was 40% (2022: 40%) consisting of a Ring Fence
Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include 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. The credit arising in 2023 of
$42.0 million was principally due the impairment of the Alba field due to forecast future production volumes. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK however adjustments to recognised deferred
PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The EPL was enacted in July 2022 with effect from 26 May 2022, at a headline rate of 25% which increased the effective UK Ring
Fenced oil and gas rate to 65% until 2025, resulting in additional current and deferred tax charges in the year to 31 December 2022. Further changes to the EPL were announced on 17 November 2022 and enacted in December 2022
whereby the Levy was increased to 35% from 1 January 2023 until 31 March 2028, increasing the effective UK Ring Fenced oil and gas tax rate to 75% resulting in an additional deferred tax charge during the year to 31 December 2022.
Deferred tax at 31 December relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Deferred corporation tax liability
(1,944,941)
(2,258,813)
Deferred corporation tax asset
2,480,921
2,629,548
Deferred PRT asset
91,759
21,721
Net deferred tax asset
627,738
392,456
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.
Non-oil and gas losses of $251 million (2022: $156 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset
these losses.
The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
392,456
220,918
Profit or loss credit/(charge)
303,767
(1,024,889)
Other comprehensive income charge
(71,700)
(200,455)
Deferred tax on decommissioning reimbursements (note 11)
3,214
\u2013
Business combinations (note 17)
\u2013
1,396,882
At 31 December
627,738
392,456
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Accelerated capital allowances
438,359
(490,246)
Tax losses
(216,937)
(386,819)
Decommissioning provision
52,440
(124,598)
Deferred PRT
(28,015)
4,173
Hedging
(101,744)
(226,040)
Share schemes
3,978
\u2013
Investment allowances
13,950
8,617
162,030
(1,214,913)
Gross deferred corporation tax liabilities
Deferred
corporation tax on Accelerated tax
Hedges deferred PRT depreciation Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
(12,861)
(675,279)
(688,140)
Prior year adjustment
\u2013
\u2013
(4,347)
(4,347)
Reclassification of decommissioning asset
\u2013
\u2013
(436,771)
(436,771)
Business combinations
\u2013
\u2013
(647,743)
(6 47,74
3)
Origination and reversal of temporary differences
\u2013
4,173
(485,985)
(481,812)
At 31 December 2022 and 1 January 2023
\u2013
(8,688)
(2,250,125)
(2,258,813)
Reclass to deferred corporation tax assets
(8,678)
\u2013
\u2013
(8,678)
Prior year adjustment
2,721
\u2013
8,307
11,028
Origination and reversal of temporary differences
(101,744)
(28,015)
441,281
311,522
At 31 December 2023
(107,701)
(36,703)
(1,800,537)
(1,944,941)
Gross deferred corporation tax assets
Decommissioning
Share schemes provision Tax losses Hedges Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
197,666
500,282
178,956
876,904
Prior year adjustment
\u2013
\u2013
3,706
\u2013
3,706
Reclassification of decommissioning asset
\u2013
436,772
\u2013
\u2013
436,772
Business combinations
\u2013
156,212
1,858,706
38,406
2,053,324
Origination and reversal of temporary differences
\u2013
(124,598)
(390,520)
(226,040)
(741,158)
At 31 December 2022 and 1 January 2023
\u2013
666,052
1,972,174
(8,678)
2,629,548
Reclass from deferred corporation tax liabilities
\u2013
\u2013
\u2013
8,678
8,678
Prior year adjustment
177
\u2013
(4,989)
\u2013
(4,812)
Origination and reversal of temporary differences
3,802
55,654
(211,949)
\u2013
(152,493)
At 31 December 2023
3,979
721,706
1,755,236
\u2013
2,480,921
Total
Deferred PRT asset US$\u2019000
At 1 January 2022
32,154
Origination and reversal of temporary differences
(10,433)
At 31 December 2022 and 1 January 2023
21,721
Origination and reversal of temporary differences
70,037
At 31 December 2023
91,758
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2023 of $536 million and $92 million respectively (2022: $371 million and $21 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 a restructuring exercise to move certain assets between Group entities which has 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 upon 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. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability
by $112.2 million.
On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective for
all accounting periods starting on or after 31 December 2023. The Group does not anticipate that the adoption of this will have a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate.
The Group has applied the exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and therefore there is no impact on the tax values reported.
", "dimensions": { "concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-481": { "value": "27. Taxation
2023 2022
US$\u2019000 US$\u2019000
Current tax
Current corporation tax charge
(39,308)
(54,557)
Current EPL tax charge
(333,425)
(131,389)
Current corporation tax (charge)/credit \u2013 prior year
(17,426)
1,839
Total current tax charge
(390,159)
(184,107)
Deferred tax
Adjustment in respect of prior period
6,370
(641)
Group tax credit/(charge) in consolidated statement of profit or loss
227,360
(1,013,817)
Group tax charge in consolidated statement of other comprehensive income
(71,700)
(200,455)
Total deferred tax credit/(charge)
162,030
(1,214,913)
Deferred Petroleum Revenue Tax
Deferred PRT credit/(charge) in statement of profit or loss
70,037
(10,432)
Total tax charge through consolidated statement of profit or loss
(86,392)
(1,208,997)
The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:
2023 2022
US$\u2019000 US$\u2019000
Accounting profit before tax
302,027
2,240,529
At tax rate of 40% (2022: 40%)
(120,811)
(896,211)
Non-deductible expense
(34,578)
(53,548)
Recognition of non-taxable gain on bargain purchase
\u2013
534,069
Financing costs not allowed for SCT
(704)
(1,958)
Ring Fence Expenditure Supplement
102,866
155,113
Deferred tax effect of investment allowance
56,930
(20,615)
Prior year adjustment
(11,673)
1,198
Deferred PRT net of corporation tax
42,022
(6,259)
Deferred tax on EPL
215,910
(766,489)
Current tax on EPL
(333,425)
(131,389)
Prior year adjustments on acquired entities
\u2013
(3,165)
Share-based payments
1,945
\u2013
Unrecognised tax losses
(4,874)
(19,743)
Total tax charge recorded in the consolidated statement of profit or loss
(86,392)
(1,208,997)
The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in both 2023 and 2022, prior to the introduction of the EPL, was 40% (2022: 40%) consisting of a Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include 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. The credit arising in 2023 of $42.0 million was principally due the impairment of the Alba field due to forecast future production volumes. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK however adjustments to recognised deferred PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The EPL was enacted in July 2022 with effect from 26 May 2022, at a headline rate of 25% which increased the effective UK Ring Fenced oil and gas rate to 65% until 2025, resulting in additional current and deferred tax charges in the year to 31 December 2022. Further changes to the EPL were announced on 17 November 2022 and enacted in December 2022 whereby the Levy was increased to 35% from 1 January 2023 until 31 March 2028, increasing the effective UK Ring Fenced oil and gas tax rate to 75% resulting in an additional deferred tax charge during the year to 31 December 2022. Deferred tax at 31 December relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Deferred corporation tax liability
(1,944,941)
(2,258,813)
Deferred corporation tax asset
2,480,921
2,629,548
Deferred PRT asset
91,759
21,721
Net deferred tax asset
627,738
392,456
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. Non-oil and gas losses of $251 million (2022: $156 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses. The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
392,456
220,918
Profit or loss credit/(charge)
303,767
(1,024,889)
Other comprehensive income charge
(71,700)
(200,455)
Deferred tax on decommissioning reimbursements (note 11)
3,214
\u2013
Business combinations (note 17)
\u2013
1,396,882
At 31 December
627,738
392,456
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Accelerated capital allowances
438,359
(490,246)
Tax losses
(216,937)
(386,819)
Decommissioning provision
52,440
(124,598)
Deferred PRT
(28,015)
4,173
Hedging
(101,744)
(226,040)
Share schemes
3,978
\u2013
Investment allowances
13,950
8,617
162,030
(1,214,913)
Gross deferred corporation tax liabilities
Deferred
corporation tax on Accelerated tax
Hedges deferred PRT depreciation Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
(12,861)
(675,279)
(688,140)
Prior year adjustment
\u2013
\u2013
(4,347)
(4,347)
Reclassification of decommissioning asset
\u2013
\u2013
(436,771)
(436,771)
Business combinations
\u2013
\u2013
(647,743)
(6 47,74
3)
Origination and reversal of temporary differences
\u2013
4,173
(485,985)
(481,812)
At 31 December 2022 and 1 January 2023
\u2013
(8,688)
(2,250,125)
(2,258,813)
Reclass to deferred corporation tax assets
(8,678)
\u2013
\u2013
(8,678)
Prior year adjustment
2,721
\u2013
8,307
11,028
Origination and reversal of temporary differences
(101,744)
(28,015)
441,281
311,522
At 31 December 2023
(107,701)
(36,703)
(1,800,537)
(1,944,941)
Gross deferred corporation tax assets
Decommissioning
Share schemes provision Tax losses Hedges Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
197,666
500,282
178,956
876,904
Prior year adjustment
\u2013
\u2013
3,706
\u2013
3,706
Reclassification of decommissioning asset
\u2013
436,772
\u2013
\u2013
436,772
Business combinations
\u2013
156,212
1,858,706
38,406
2,053,324
Origination and reversal of temporary differences
\u2013
(124,598)
(390,520)
(226,040)
(741,158)
At 31 December 2022 and 1 January 2023
\u2013
666,052
1,972,174
(8,678)
2,629,548
Reclass from deferred corporation tax liabilities
\u2013
\u2013
\u2013
8,678
8,678
Prior year adjustment
177
\u2013
(4,989)
\u2013
(4,812)
Origination and reversal of temporary differences
3,802
55,654
(211,949)
\u2013
(152,493)
At 31 December 2023
3,979
721,706
1,755,236
\u2013
2,480,921
Total
Deferred PRT asset US$\u2019000
At 1 January 2022
32,154
Origination and reversal of temporary differences
(10,433)
At 31 December 2022 and 1 January 2023
21,721
Origination and reversal of temporary differences
70,037
At 31 December 2023
91,758
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2023 of $536 million and $92 million respectively (2022: $371 million and $21 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 a restructuring exercise to move certain assets between Group entities which has 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 upon 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. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million. On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective for all accounting periods starting on or after 31 December 2023. The Group does not anticipate that the adoption of this will have a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate. The Group has applied the exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and therefore there is no impact on the tax values reported.", "dimensions": { "concept": "ifrs-full:DisclosureOfTaxReceivablesAndPayablesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-465": { "value": "27. Taxation
2023 2022
US$\u2019000 US$\u2019000
Current tax
Current corporation tax charge
(39,308)
(54,557)
Current EPL tax charge
(333,425)
(131,389)
Current corporation tax (charge)/credit \u2013 prior year
(17,426)
1,839
Total current tax charge
(390,159)
(184,107)
Deferred tax
Adjustment in respect of prior period
6,370
(641)
Group tax credit/(charge) in consolidated statement of profit or loss
227,360
(1,013,817)
Group tax charge in consolidated statement of other comprehensive income
(71,700)
(200,455)
Total deferred tax credit/(charge)
162,030
(1,214,913)
Deferred Petroleum Revenue Tax
Deferred PRT credit/(charge) in statement of profit or loss
70,037
(10,432)
Total tax charge through consolidated statement of profit or loss
(86,392)
(1,208,997)
The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:
2023 2022
US$\u2019000 US$\u2019000
Accounting profit before tax
302,027
2,240,529
At tax rate of 40% (2022: 40%)
(120,811)
(896,211)
Non-deductible expense
(34,578)
(53,548)
Recognition of non-taxable gain on bargain purchase
\u2013
534,069
Financing costs not allowed for SCT
(704)
(1,958)
Ring Fence Expenditure Supplement
102,866
155,113
Deferred tax effect of investment allowance
56,930
(20,615)
Prior year adjustment
(11,673)
1,198
Deferred PRT net of corporation tax
42,022
(6,259)
Deferred tax on EPL
215,910
(766,489)
Current tax on EPL
(333,425)
(131,389)
Prior year adjustments on acquired entities
\u2013
(3,165)
Share-based payments
1,945
\u2013
Unrecognised tax losses
(4,874)
(19,743)
Total tax charge recorded in the consolidated statement of profit or loss
(86,392)
(1,208,997)
The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in both 2023 and 2022, prior to the introduction of the EPL, was 40% (2022: 40%) consisting of a Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include 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. The credit arising in 2023 of $42.0 million was principally due the impairment of the Alba field due to forecast future production volumes. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK however adjustments to recognised deferred PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The EPL was enacted in July 2022 with effect from 26 May 2022, at a headline rate of 25% which increased the effective UK Ring Fenced oil and gas rate to 65% until 2025, resulting in additional current and deferred tax charges in the year to 31 December 2022. Further changes to the EPL were announced on 17 November 2022 and enacted in December 2022 whereby the Levy was increased to 35% from 1 January 2023 until 31 March 2028, increasing the effective UK Ring Fenced oil and gas tax rate to 75% resulting in an additional deferred tax charge during the year to 31 December 2022. Deferred tax at 31 December relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Deferred corporation tax liability
(1,944,941)
(2,258,813)
Deferred corporation tax asset
2,480,921
2,629,548
Deferred PRT asset
91,759
21,721
Net deferred tax asset
627,738
392,456
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. Non-oil and gas losses of $251 million (2022: $156 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses. The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:
2023 2022
US$\u2019000 US$\u2019000
At 1 January
392,456
220,918
Profit or loss credit/(charge)
303,767
(1,024,889)
Other comprehensive income charge
(71,700)
(200,455)
Deferred tax on decommissioning reimbursements (note 11)
3,214
\u2013
Business combinations (note 17)
\u2013
1,396,882
At 31 December
627,738
392,456
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income relates to the following:
2023 2022
US$\u2019000 US$\u2019000
Accelerated capital allowances
438,359
(490,246)
Tax losses
(216,937)
(386,819)
Decommissioning provision
52,440
(124,598)
Deferred PRT
(28,015)
4,173
Hedging
(101,744)
(226,040)
Share schemes
3,978
\u2013
Investment allowances
13,950
8,617
162,030
(1,214,913)
Gross deferred corporation tax liabilities
Deferred
corporation tax on Accelerated tax
Hedges deferred PRT depreciation Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
(12,861)
(675,279)
(688,140)
Prior year adjustment
\u2013
\u2013
(4,347)
(4,347)
Reclassification of decommissioning asset
\u2013
\u2013
(436,771)
(436,771)
Business combinations
\u2013
\u2013
(647,743)
(6 47,74
3)
Origination and reversal of temporary differences
\u2013
4,173
(485,985)
(481,812)
At 31 December 2022 and 1 January 2023
\u2013
(8,688)
(2,250,125)
(2,258,813)
Reclass to deferred corporation tax assets
(8,678)
\u2013
\u2013
(8,678)
Prior year adjustment
2,721
\u2013
8,307
11,028
Origination and reversal of temporary differences
(101,744)
(28,015)
441,281
311,522
At 31 December 2023
(107,701)
(36,703)
(1,800,537)
(1,944,941)
Gross deferred corporation tax assets
Decommissioning
Share schemes provision Tax losses Hedges Total
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
At 1 January 2022
\u2013
197,666
500,282
178,956
876,904
Prior year adjustment
\u2013
\u2013
3,706
\u2013
3,706
Reclassification of decommissioning asset
\u2013
436,772
\u2013
\u2013
436,772
Business combinations
\u2013
156,212
1,858,706
38,406
2,053,324
Origination and reversal of temporary differences
\u2013
(124,598)
(390,520)
(226,040)
(741,158)
At 31 December 2022 and 1 January 2023
\u2013
666,052
1,972,174
(8,678)
2,629,548
Reclass from deferred corporation tax liabilities
\u2013
\u2013
\u2013
8,678
8,678
Prior year adjustment
177
\u2013
(4,989)
\u2013
(4,812)
Origination and reversal of temporary differences
3,802
55,654
(211,949)
\u2013
(152,493)
At 31 December 2023
3,979
721,706
1,755,236
\u2013
2,480,921
Total
Deferred PRT asset US$\u2019000
At 1 January 2022
32,154
Origination and reversal of temporary differences
(10,433)
At 31 December 2022 and 1 January 2023
21,721
Origination and reversal of temporary differences
70,037
At 31 December 2023
91,758
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2023 of $536 million and $92 million respectively (2022: $371 million and $21 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 a restructuring exercise to move certain assets between Group entities which has 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 upon 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. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million. On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective for all accounting periods starting on or after 31 December 2023. The Group does not anticipate that the adoption of this will have a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate. The Group has applied the exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and therefore there is no impact on the tax values reported.", "dimensions": { "concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-466": { "value": "
28. Commitments and contingencies
2023 2022
US$\u2019000 US$\u2019000
Capital commitments
Capital commitments incurred jointly with other venturers (Group\u2019s share)
506,959
52,309
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 2023, the Group had commitments
for future capital expenditure amounting to $507 million (2022: $52.3 million). The key component of this relates to Rosebank, following FID approval in September 2023. Additionally, there are commitments in relation to AFEs
(authorisations for expenditure) signed for activities on Captain enhanced oil extraction.
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 2023 the Group had $450
million (31 December 2022: $469 million) in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements.
", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-437": { "value": "28. Commitments and contingencies
2023 2022
US$\u2019000 US$\u2019000
Capital commitments
Capital commitments incurred jointly with other venturers (Group\u2019s share)
506,959
52,309
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 2023, the Group had commitments for future capital expenditure amounting to $507 million (2022: $52.3 million). The key component of this relates to Rosebank, following FID approval in September 2023. Additionally, there are commitments in relation to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction. 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 2023 the Group had $450 million (31 December 2022: $469 million) in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements.", "dimensions": { "concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-482": { "value": "28. Commitments and contingencies
2023 2022
US$\u2019000 US$\u2019000
Capital commitments
Capital commitments incurred jointly with other venturers (Group\u2019s share)
506,959
52,309
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 2023, the Group had commitments for future capital expenditure amounting to $507 million (2022: $52.3 million). The key component of this relates to Rosebank, following FID approval in September 2023. Additionally, there are commitments in relation to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction. 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 2023 the Group had $450 million (31 December 2022: $469 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-467": { "value": "29. 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 \u2018other gains and losses\u2019 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 parent entity 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 2023 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through in hedge Total carrying
amortised cost profit or loss relationships amount
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Financial assets
Cash and cash equivalents
153,215
\u2013
\u2013
153,215
Trade and other receivables
330,351
\u2013
\u2013
330,351
Derivative financial instruments
\u2013
2,782
154,525
157,307
Financial liabilities
Borrowings
(748,151)
\u2013
\u2013
(748,151)
Trade and other payables
(343,279)
\u2013
\u2013
(343,279)
Lease liability
(20,559)
\u2013
\u2013
(20,559)
Contingent and deferred consideration
(63,979)
(296,390)
\u2013
(360,369)
Derivative financial instruments
\u2013
(10,373)
(3,335)
(13,708)
(845,193)
The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2022 are set out below:
Mandatorily Derivatives
measured at fair designated
Measured at value through in hedge Total carrying
amortised cost profit or loss relationships amount
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Financial assets
Cash and cash equivalents
253,822
\u2013
\u2013
253,822
Trade and other receivables
359,994
\u2013
\u2013
359,994
Derivative financial instruments
\u2013
7,125
164,924
172,049
Financial liabilities
Borrowings
(1,213,731)
\u2013
\u2013
(1,213,731)
Trade and other payables
(618,460)
\u2013
\u2013
(618,460)
Lease liability
(58,858)
\u2013
\u2013
(58,858)
Contingent and deferred consideration
(67,9
0 4)
(258,896)
\u2013
(326,800)
Derivative financial instruments
\u2013
(57,546)
(106,563)
(164,109)
(1,596,093)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2023:
Level 1 Level 2 Level 3 Total Fair Value
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Contingent consideration (note 25)
\u2013
(24,039)
(272,351)
(296,390)
Derivative financial instrument asset
\u2013
157,307
\u2013
157,307
Derivative financial instrument liability
\u2013
(13,708)
\u2013
(13,708)
Movements in level 3 financial instruments in the 12 months to 31 December 2023 were as follows:
US$\u2019000
At 1 January 2023
(223,246)
Additions
(26,872)
Cash settlement
\u2013
Accretion
(8,799)
Changes in fair value
(13,434)
At 31 December 2023
(272,351)
The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as at 31 December 2022:
Level 1 Level 2 Level 3 Total Fair Value
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Contingent consideration (note 25)
\u2013
(35,650)
(223,246)
(258,896)
Derivative financial instrument asset
\u2013
172,049
\u2013
172,049
Derivative financial instrument liability
\u2013
(164,109)
\u2013
(164,109)
Movements in level 3 financial instruments in the 12 months to 31 December 2022 were as follows:
US$\u2019000
At 1 January 2022
(19,480)
Business combinations
(210,096)
Release of provision
1,100
Accretion
(5,208)
Changes in fair value
10,438
At 31 December 2022
(223,246)
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 $23.3 million (2022: $36.4 million). A 20% increase in the oil price would lead to an increase in contingent consideration of $41.0 million (2022: $26.4 million). The level three contingent consideration is valued based on the probability of the events occurring (\u201ctrigger events\u201d) as set out in note 17. The forecast cash flows in the event of the trigger event occurring are discounted at a rate of 4.6% (2022: 4.25%). The following table summarises the sensitivity of 20% change in probability of trigger event occurring and conditions being met for payment of contingent consideration, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in probability
2023 2022
US$\u2019000 US$\u2019000
20% decrease in probability
97,119
87,0 8 0
20% increase in probability
(84,086)
(83,612)
The following table summarises the sensitivity of 1% decrease in discount rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in discount rate
2023 2022
US$\u2019000 US$\u2019000
1% decrease in discount rate
(5,284)
(4,374)
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 2023 and 31 December 2022, 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 $748.2 million (2022: $1,213.7 million) and the equivalent fair value is $781.4 million (2022: $1,257.9 million) per level 1 of the fair value hierarchy. The table below presents the total gain on financial instruments that has been disclosed through the consolidated statement of profit or loss:
2023 2022
US$\u2019000 US$\u2019000
Revaluation of forex forward contracts
7,313
(28,172)
Revaluation of interest rate swaps
(6,488)
\u2013
Revaluation of commodity hedges
42,006
44,959
Total revaluation gain on financial instruments
42,831
16,787
Realised loss on forex forward contracts
(6,282)
\u2013
Realised gain on interest rate swaps
6,967
\u2013
Realised loss on commodity hedges
(457)
(16,215)
Total gain on financial instruments
43,059
572
", "dimensions": { "concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-483": { "value": "
Mandatorily Derivatives
measured at fair designated
Measured at value through in hedge Total carrying
amortised cost profit or loss relationships amount
US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000
Financial assets
Cash and cash equivalents
153,215
\u2013
\u2013
153,215
Trade and other receivables
330,351
\u2013
\u2013
330,351
Derivative financial instruments
\u2013
2,782
154,525
157,307
Financial liabilities
Borrowings
(748,151)
\u2013
\u2013
(748,151)
Trade and other payables
(343,279)
\u2013
\u2013
(343,279)
Lease liability
(20,559)
\u2013
\u2013
(20,559)
Contingent and deferred consideration
(63,979)
(296,390)
\u2013
(360,369)
Derivative financial instruments
\u2013
(10,373)
(3,335)
(13,708)
(845,193)
The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2022 are set out below: Mandatorily Derivatives measured at fair designated Measured at value through in hedge Total carrying amortised cost profit or loss relationships amount US$\u2019000 US$\u2019000 US$\u2019000 US$\u2019000 Financial assets Cash and cash equivalents 253,822 \u2013 \u2013 253,822 Trade and other receivables 359,994 \u2013 \u2013 359,994 Derivative financial instruments \u2013 7,125 164,924 172,049 Financial liabilities Borrowings (1,213,731) \u2013 \u2013 (1,213,731) Trade and other payables (618,460) \u2013 \u2013 (618,460) Lease liability (58,858) \u2013 \u2013 (58,858) Contingent and deferred consideration (67,9 0 4) (258,896) \u2013 (326,800) Derivative financial instruments \u2013 (57,546) (106,563) (164,109) (1,596,093", "dimensions": { "concept": "ifrs-full:DisclosureOfFinancialInstrumentsAtFairValueThroughProfitOrLossExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-495": { "value": "Cash flow hedge reserve The table below presents the movement in financial instruments that has been disclosed through the statement of comprehensive income relating to the cash flow hedge reserve: Cash flow hedge reserve
2023 2022
US$\u2019000 US$\u2019000
At 1 January
16,710
(242,791)
Change in fair value of derivative instruments
358,141
(46,800)
Amounts recycled to revenue
(265,711)
501,513
Amounts recycled to finance costs
\u2013
(851)
Deferred tax on movement in year
(69,322)
(194,361)
Cash flow hedge reserve at 31 December
39,818
16,710
Cost of hedging reserve The table below presents the movement in financial instruments that has been disclosed through the statement of comprehensive income relating to the cost of hedging reserve: Cost of hedging reserve
2023 2022
US$\u2019000 US$\u2019000
At 1 January
3,275
(4,862)
Change in fair value of the intrinsic value of derivative instruments
(12,269)
(42,745)
Amounts recycled to revenue \u2013 oil put premiums
11,850
14,629
Amounts recycled to revenue \u2013 gas put premiums
3,590
42,347
Deferred tax on movement in year
(2,378)
(6,094)
Cost of hedging reserve at 31 December
4,068
3,275
30. Derivative financial instruments The net carrying amount of each category of derivative is set out below:
2023 2022
US$\u2019000 US$\u2019000
Oil swaps \u2013 cash flow hedge
9,913
(28,685)
Oil swaps \u2013 non-cash flow hedge
\u2013
(15,027)
Oil collars \u2013 cash flow hedge
7,434
(21,983)
Gas swaps \u2013 cash flow hedge
47, 232
19,797
Gas swaps \u2013 non-cash flow hedge
(2,290)
(29,271)
Gas puts \u2013 cash flow hedge
\u2013
9,746
Gas collars \u2013 cash flow hedge
89,944
79,489
Interest rate swaps \u2013 non-cash flow hedge
637
7,125
FX forwards \u2013 non-cash flow hedge
(3,961)
(13,250)
FX collars \u2013 cash flow hedge
(3,335)
\u2013
FX collars \u2013 non-cash flow hedge
(1,975)
\u2013
143,599
7,941
2023 2022
Maturity analysis of derivative financial instruments US$\u2019000 US$\u2019000
Non-current assets
17,810
21,191
Current assets
139,497
150,858
Non-current liabilities
\u2013
(27,4 4 0)
Current liabilities
(13,708)
(136,668)
143,599
7,941
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 $113 million (2022: $179 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 2023 of $88 million (2022: $188 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 2023 and 2022. Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2023 are detailed below:
Related amounts not set off in balance
Amount recognised in balance sheet sheet Net amount
$\u2019000 $\u2019000 $\u2019000
Derivative assets
157, 30 6
(4,436)
152,870
Derivative liabilities
(13,708)
4,436
(9,272)
Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2022 are detailed below:
Related amounts not set off in balance
Amount recognised in balance sheet sheet Net amount
$\u2019000 $\u2019000 $\u2019000
Derivative assets
172,049
(33,117)
138,932
Derivative liabilities
(164,109)
33,117
(130,992)
", "dimensions": { "concept": "ifrs-full:DisclosureOfHedgeAccountingExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-468": { "value": "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 12-month period under the RBL, the Group is required to hedge a minimum of 70% of volumes of net RBL entitlement production expected to be produced in the next 12 months, and 50% of volumes of net RBL entitlement produced for the following 12 months on a best-effort basis. The 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 below represents total commodity hedges in place at the 2022 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 23 \u2013 Jun 24
3,390,500
bbls
$70/bbl
Oil collars
Jan 23 \u2013 Dec 23
4,560,000
bbls
$68/bbl floor \u2013 $91/bbl ceiling
Gas swaps
Jan 23 \u2013 Jun 24
104,585,000
therms
188p/therm
Gas puts
Apr 23 \u2013 Sep 23
9,150,000
therms
220p/therm
Gas collars
Jan 23 \u2013 Mar 24
100,200,000
therms
244p/therm floor \u2013 479p/therm ceiling
The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in realised commodity price
2023 2022
US$\u2019000 US$\u2019000
20% decrease in realised oil price
(177,151)
(246,914)
20% decrease in realised gas price
(146,794)
(330,285)
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 bp unsecured loan 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 material interest rate financial instruments in place at 31 December 2023. The below represents interest rate financial instruments in place at the 2022 year end:
Derivative Term
Value
Rate
Interest rate swap (floating to fixed)
Jan 22 \u2013 Dec 23
$150 million
0.398%
The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. Change in interest rate
2023 2022
US$\u2019000 US$\u2019000
Increase of 250 basis points
(22,370)
(11,126)
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 upon spot rate fluctuations from year-to-year. 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. As at 31 December 2022 the Group had an average of \u00a35.5 million per quarter hedged at an average forward rate of $1.265:\u00a31 for the period January to December 2023. As at 31 December 2022 the Group had no open FX collars. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is not material. Change in Sterling foreign exchange rate
2023 2022
US$\u2019000 US$\u2019000
10% weakening of Sterling against the US Dollar
(123,033)
(139,633)
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. iv) Credit risk The majority of the Group\u2019s trade and other receivables are with customers in the oil and gas industry 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. Oil production from Stella, Vorlich, Jade and Abigail fields is sold to ENI, Columba is sold to Repsol, Mariner to Equinor ASA, Pierce to Shell International Trading, and Captain, Alba, Cook, Forties (including MonArb) and Schiehallion fields to BP Oil International. Forties fields (including MonArb), Stella, Vorlich, Jade and Abigail gas is sold to BP Gas Marketing. Cook gas is sold to Shell International Trading and Esso Exploration, and Schiehallion to EnQuest. 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 2023, 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 2023 (31 December 2022: $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 2023, the Group\u2019s exposure is $nil (31 December 2022: $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 parent entity 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 2022 and 2023 substantially all accounts payable are current. 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 US$\u2019000 US$\u2019000 US\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(343,279)
\u2013
\u2013
(343,279)
(343,279)
Contingent and deferred consideration
\u2013
(101,669)
(248,388)
(44,508)
(394,565)
(360,369)
Lease liabilities
6.07%
(20,152)
(669)
\u2013
(20,821)
(20,559)
Borrowings
8.02%
(64,190)
(840,085)
\u2013
(904,275)
(748,151)
(529,290)
(1,089,142)
(44,508)
(1,662,940)
(1,472,358)
The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2022:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate US$\u2019000 US$\u2019000 US\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(618,460)
\u2013
\u2013
(618,460)
(618,460)
Contingent and deferred consideration
\u2013
(107,680)
(226,842)
(23,668)
(358,190)
(326,800)
Lease liabilities
6.38%
(44,257)
(17,439)
\u2013
(61,696)
(58,858)
Borrowings
8.85%
(98,250)
(1,474,528)
\u2013
(1,572,778)
(1,235,454)
(868,647)
(1,718,809)
(23,668)
(2,611,124)
(2,239,572)
The following table details the Group\u2019s liquidity analysis for its derivative financial instruments based on contractual maturities. The table has been drawn up based on the undiscounted net cash inflows and outflows on derivative instruments that settle on a net basis, and the undiscounted gross inflows and outflows on those derivatives that require gross settlement. When the amount payable or receivable is not fixed, the amount disclosed has been determined by reference to the projected interest rates as illustrated by the yield curves existing at the reporting date. At 31 December 2023
Within
1 year Within 2 to 5 years Total
US$\u2019000 US$\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(2,290)
\u2013
(2,290)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(113,342)
\u2013
(113,342)
Foreign exchange collars \u2013 gross outflows
(155,071)
\u2013
(155,071)
(270,703)
\u2013
(270,703)
At 31 December 2022
Within
1 year Within 2 to 5 years Total
US$\u2019000 US$\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(51,654)
(15,402)
(67,056)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(83,529)
(107,235)
(190,764)
Foreign exchange collars \u2013 gross outflows
\u2013
\u2013
\u2013
(135,183)
(122,637)
(257, 820)
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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-484": { "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 12-month period under the RBL, the Group is required to hedge a minimum of 70% of volumes of net RBL entitlement production expected to be produced in the next 12 months, and 50% of volumes of net RBL entitlement produced for the following 12 months on a best-effort basis. The 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 below represents total commodity hedges in place at the 2022 year-end:
Derivative
Term
Volume
Average price
Oil swaps
Jan 23 \u2013 Jun 24
3,390,500
bbls
$70/bbl
Oil collars
Jan 23 \u2013 Dec 23
4,560,000
bbls
$68/bbl floor \u2013 $91/bbl ceiling
Gas swaps
Jan 23 \u2013 Jun 24
104,585,000
therms
188p/therm
Gas puts
Apr 23 \u2013 Sep 23
9,150,000
therms
220p/therm
Gas collars
Jan 23 \u2013 Mar 24
100,200,000
therms
244p/therm floor \u2013 479p/therm ceiling
The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in realised commodity price
2023 2022
US$\u2019000 US$\u2019000
20% decrease in realised oil price
(177,151)
(246,914)
20% decrease in realised gas price
(146,794)
(330,285)
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 bp unsecured loan 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 material interest rate financial instruments in place at 31 December 2023. The below represents interest rate financial instruments in place at the 2022 year end:
Derivative Term
Value
Rate
Interest rate swap (floating to fixed)
Jan 22 \u2013 Dec 23
$150 million
0.398%
The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. Change in interest rate
2023 2022
US$\u2019000 US$\u2019000
Increase of 250 basis points
(22,370)
(11,126)
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 upon spot rate fluctuations from year-to-year. 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. As at 31 December 2022 the Group had an average of \u00a35.5 million per quarter hedged at an average forward rate of $1.265:\u00a31 for the period January to December 2023. As at 31 December 2022 the Group had no open FX collars. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is not material. Change in Sterling foreign exchange rate
2023 2022
US$\u2019000 US$\u2019000
10% weakening of Sterling against the US Dollar
(123,033)
(139,633)
A 10% strengthening of Sterling against the US Dollar would have had the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. ", "dimensions": { "concept": "ifrs-full:DisclosureOfMarketRiskExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-496": { "value": "The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in realised commodity price
2023 2022
US$\u2019000 US$\u2019000
20% decrease in realised oil price
(177,151)
(246,914)
20% decrease in realised gas price
(146,794)
(330,285)
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 below represents interest rate financial instruments in place at the 2022 year end:
Derivative Term
Value
Rate
Interest rate swap (floating to fixed)
Jan 22 \u2013 Dec 23
$150 million
0.398%
The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. Change in interest rate
2023 2022
US$\u2019000 US$\u2019000
Increase of 250 basis points
(22,370)
(11,126)
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. As at 31 December 2022 the Group had an average of \u00a35.5 million per quarter hedged at an average forward rate of $1.265:\u00a31 for the period January to December 2023. As at 31 December 2022 the Group had no open FX collars. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is not material. Change in Sterling foreign exchange rate
2023 2022
US$\u2019000 US$\u2019000
10% weakening of Sterling against the US Dollar
(123,033)
(139,633)
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. ", "dimensions": { "concept": "ifrs-full:SensitivityAnalysisForEachTypeOfMarketRisk", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-485": { "value": "iv) Credit risk The majority of the Group\u2019s trade and other receivables are with customers in the oil and gas industry 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. Oil production from Stella, Vorlich, Jade and Abigail fields is sold to ENI, Columba is sold to Repsol, Mariner to Equinor ASA, Pierce to Shell International Trading, and Captain, Alba, Cook, Forties (including MonArb) and Schiehallion fields to BP Oil International. Forties fields (including MonArb), Stella, Vorlich, Jade and Abigail gas is sold to BP Gas Marketing. Cook gas is sold to Shell International Trading and Esso Exploration, and Schiehallion to EnQuest. 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 2023, 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 2023 (31 December 2022: $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 2023, the Group\u2019s exposure is $nil (31 December 2022: $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 parent entity 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": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-486": { "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 2022 and 2023 substantially all accounts payable are current. 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 US$\u2019000 US$\u2019000 US\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(343,279)
\u2013
\u2013
(343,279)
(343,279)
Contingent and deferred consideration
\u2013
(101,669)
(248,388)
(44,508)
(394,565)
(360,369)
Lease liabilities
6.07%
(20,152)
(669)
\u2013
(20,821)
(20,559)
Borrowings
8.02%
(64,190)
(840,085)
\u2013
(904,275)
(748,151)
(529,290)
(1,089,142)
(44,508)
(1,662,940)
(1,472,358)
The following table shows the timing of cash outflows, including future interest, relating to financial liabilities, excluding derivatives, at 31 December 2022:
Weighted average Within
effective interest 1 year Within 2 to 5 years More than 5 years Total Carrying amount
rate US$\u2019000 US$\u2019000 US\u2019000 $\u2019000 $\u2019000
Trade and other payables
\u2013
(618,460)
\u2013
\u2013
(618,460)
(618,460)
Contingent and deferred consideration
\u2013
(107,680)
(226,842)
(23,668)
(358,190)
(326,800)
Lease liabilities
6.38%
(44,257)
(17,439)
\u2013
(61,696)
(58,858)
Borrowings
8.85%
(98,250)
(1,474,528)
\u2013
(1,572,778)
(1,235,454)
(868,647)
(1,718,809)
(23,668)
(2,611,124)
(2,239,572)
The following table details the Group\u2019s liquidity analysis for its derivative financial instruments based on contractual maturities. The table has been drawn up based on the undiscounted net cash inflows and outflows on derivative instruments that settle on a net basis, and the undiscounted gross inflows and outflows on those derivatives that require gross settlement. When the amount payable or receivable is not fixed, the amount disclosed has been determined by reference to the projected interest rates as illustrated by the yield curves existing at the reporting date. At 31 December 2023
Within
1 year Within 2 to 5 years Total
US$\u2019000 US$\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(2,290)
\u2013
(2,290)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(113,342)
\u2013
(113,342)
Foreign exchange collars \u2013 gross outflows
(155,071)
\u2013
(155,071)
(270,703)
\u2013
(270,703)
At 31 December 2022
Within
1 year Within 2 to 5 years Total
US$\u2019000 US$\u2019000 $\u2019000
Net-settled (derivative liabilities):
Commodity options
(51,654)
(15,402)
(67,056)
Gross-settled:
Foreign exchange forwards \u2013 gross outflows
(83,529)
(107,235)
(190,764)
Foreign exchange collars \u2013 gross outflows
\u2013
\u2013
\u2013
(135,183)
(122,637)
(257, 820)
", "dimensions": { "concept": "ifrs-full:DisclosureOfLiquidityRiskExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-487": { "value": "vi) Capital management The Group\u2019s objectives when managing capital are to safeguard the Group\u2019s ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required. The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates eroding the Group\u2019s financial results. ", "dimensions": { "concept": "ifrs-full:DisclosureOfObjectivesPoliciesAndProcessesForManagingCapitalExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-488": { "value": "30. Derivative financial instruments The net carrying amount of each category of derivative is set out below:
2023 2022
US$\u2019000 US$\u2019000
Oil swaps \u2013 cash flow hedge
9,913
(28,685)
Oil swaps \u2013 non-cash flow hedge
\u2013
(15,027)
Oil collars \u2013 cash flow hedge
7,434
(21,983)
Gas swaps \u2013 cash flow hedge
47, 232
19,797
Gas swaps \u2013 non-cash flow hedge
(2,290)
(29,271)
Gas puts \u2013 cash flow hedge
\u2013
9,746
Gas collars \u2013 cash flow hedge
89,944
79,489
Interest rate swaps \u2013 non-cash flow hedge
637
7,125
FX forwards \u2013 non-cash flow hedge
(3,961)
(13,250)
FX collars \u2013 cash flow hedge
(3,335)
\u2013
FX collars \u2013 non-cash flow hedge
(1,975)
\u2013
143,599
7,941
2023 2022
Maturity analysis of derivative financial instruments US$\u2019000 US$\u2019000
Non-current assets
17,810
21,191
Current assets
139,497
150,858
Non-current liabilities
\u2013
(27,4 4 0)
Current liabilities
(13,708)
(136,668)
143,599
7,941
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 $113 million (2022: $179 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 2023 of $88 million (2022: $188 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 2023 and 2022. Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2023 are detailed below:
Related amounts not set off in balance
Amount recognised in balance sheet sheet Net amount
$\u2019000 $\u2019000 $\u2019000
Derivative assets
157, 30 6
(4,436)
152,870
Derivative liabilities
(13,708)
4,436
(9,272)
Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2022 are detailed below:
Related amounts not set off in balance
Amount recognised in balance sheet sheet Net amount
$\u2019000 $\u2019000 $\u2019000
Derivative assets
172,049
(33,117)
138,932
Derivative liabilities
(164,109)
33,117
(130,992)
", "dimensions": { "concept": "ifrs-full:DisclosureOfDerivativeFinancialInstrumentsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-438": { "value": "
31. Related-party transactions
The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) who owns 88.55% of the issued share capital of Ithaca Energy plc. The registered office address of the DKL Energy Limited is 47 Esplanade, St Helier,
Jersey, JE1 0BD.
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.
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
2023
2022
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%
Transactions between subsidiaries are eliminated on consolidation.
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
Amounts owed to Delek Group Limited
An outstanding interest amount of $29 million with respect to a historic related party loan with Delek Group Limited was repaid in full on 4 October 2022.
The movement in capital loan notes during the year ended 31 December 2022 related to imputed interest of $18 million on the unwind of the capital contribution and subsequent settlement of the $392 million balance under
a waiver agreement.
On 8 November 2022, a waiver agreement was signed by DKL Energy Limited, the immediate parent Company of Ithaca Energy plc at that time, to partially waive a capital note balance and a subordinated loan balance (including interest)
totalling $469 million, such that, post-IPO these balances would no longer be due from Ithaca Energy plc.
A loan waiver of $181.9 million was recognised as a Capital Contribution on equity in the year to 31 December 2022.
Key management personnel
The following table provides remuneration to key management personnel, being persons having direct or indirect authority or responsibility of the Group, for the periods ended 31 December 2023 and 2022:
Key management personnel
2023 2022
US$\u2019000 US$\u2019000
Salaries and short-term employee benefits
5,741
4,590
Payments made in lieu of pension contributions
249
229
Company pension contributions
106
106
Share-based payment
5,863
12,623
11,959
17,5 4 8
Further detail regarding share-based payments received by key management personnel is set out below.
", "dimensions": { "concept": "ifrs-full:DisclosureOfRelatedPartyExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-469": { "value": "31. Related-party transactions The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) who owns 88.55% of the issued share capital of Ithaca Energy plc. The registered office address of the DKL Energy Limited is 47 Esplanade, St Helier, Jersey, JE1 0BD. 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. 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
2023
2022
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%
Transactions between subsidiaries are eliminated on consolidation. 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 Amounts owed to Delek Group Limited An outstanding interest amount of $29 million with respect to a historic related party loan with Delek Group Limited was repaid in full on 4 October 2022. The movement in capital loan notes during the year ended 31 December 2022 related to imputed interest of $18 million on the unwind of the capital contribution and subsequent settlement of the $392 million balance under a waiver agreement. On 8 November 2022, a waiver agreement was signed by DKL Energy Limited, the immediate parent Company of Ithaca Energy plc at that time, to partially waive a capital note balance and a subordinated loan balance (including interest) totalling $469 million, such that, post-IPO these balances would no longer be due from Ithaca Energy plc. A loan waiver of $181.9 million was recognised as a Capital Contribution on equity in the year to 31 December 2022. Key management personnel The following table provides remuneration to key management personnel, being persons having direct or indirect authority or responsibility of the Group, for the periods ended 31 December 2023 and 2022: Key management personnel
2023 2022
US$\u2019000 US$\u2019000
Salaries and short-term employee benefits
5,741
4,590
Payments made in lieu of pension contributions
249
229
Company pension contributions
106
106
Share-based payment
5,863
12,623
11,959
17,5 4 8
Further detail regarding share-based payments received by key management personnel is set out below.", "dimensions": { "concept": "ifrs-full:DisclosureOfTransactionsBetweenRelatedPartiesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-7": { "value": "DKL Energy Limited ", "dimensions": { "concept": "ifrs-full:NameOfParentEntity", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-8": { "value": "Delek Group Limited", "dimensions": { "concept": "ifrs-full:NameOfUltimateParentOfGroup", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "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
2023
2022
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%
Transactions between subsidiaries are eliminated on consolidation. 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 ", "dimensions": { "concept": "ifrs-full:DisclosureOfSignificantInvestmentsInSubsidiariesExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-489": { "value": "Key management personnel The following table provides remuneration to key management personnel, being persons having direct or indirect authority or responsibility of the Group, for the periods ended 31 December 2023 and 2022: Key management personnel
2023 2022
US$\u2019000 US$\u2019000
Salaries and short-term employee benefits
5,741
4,590
Payments made in lieu of pension contributions
249
229
Company pension contributions
106
106
Share-based payment
5,863
12,623
11,959
17,5 4 8
Further detail regarding share-based payments received by key management personnel is set out below.", "dimensions": { "concept": "ifrs-full:DisclosureOfInformationAboutKeyManagementPersonnelExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-439": { "value": "
32. Share-based payments
The charge for share-based payment transactions in the year to 31 December 2023 was $16.4 million (2022: $14.1 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)
Outstanding share options under LTIPs were as follows:
Heritage awards
At-IPO awards
2022
LTIP awards
Total
Balance at 1 January 2022
\u2013
\u2013
\u2013
\u2013
Granted during the year
1,687,296
4,908,903
2,836,660
9,432,859
Balance at 31 December 2022
1,687,296
4,908,903
2,836,660
9,432,859
Awarded during the year in lieu of dividend payments
191,401
190,426
\u2013
381,827
Forfeited during the year
(127,880)
(296,966)
(276,123)
(700,969)
Exercised during the year
(921,882)
(521,679)
\u2013
(1,443,561)
Balance at 31 December 2023
828,935
4,280,684
2,560,537
7,670,156
Exercisable at 31 December 2023
828,935
1,220,692
\u2013
2,049,627
Share option exercise price
\u00a3nil
\u00a3nil
\u00a3nil
N/A
Weighted average share price on date of exercise
\u00a31.56
\u00a31.56
N/A
N/A
Weighted average remaining life
N/A
1.9 years
2.3 years
N/A
All LTIP awards are nil-cost options. There are no performance conditions attaching to the Heritage and At-IPO awards. Details of the performance conditions of the 2022 LTIP are set out in the Directors\u2019 remuneration 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 and the 2022 LTIP awards vest over the period to 1 April 2026. It is anticipated that future exercises of LTIP awards will be settled by equity. The total charge for LTIP share options in the year to 31 December 2023
was $12.9 million (2022: $0.6 million).
IPO-related share options
Under the terms section 11.6 of the Prospectus, the Executive Chairman, Gilad Myerson (GM) and the former Chief Executive Officer, Alan Bruce (AB) were entitled to an award of share options worth 0.2% of the value of the
Group immediately on IPO which valued these awards at $5.0 million or 2,337,931 share options each. There are no performance conditions attaching to these share options. The exercise price of each of the share options is \u00a30.01.
Mr Myerson\u2019s share options vested immediately on IPO and Mr Bruce\u2019s share options were vesting equally over the period 21 July 2021 to 20 July 2026. During the year to 31 December 2022 Mr Myerson exercised 1,402,759 share
options. The total charge for IPO-related share options in the year to 31 December 2023 was $0.5 million (2022: $7.3 million).
GM options
AB options
Total
Balance at 1 January 2023
935,172
2,337,931
3,273,103
Exercised during the year
\u2013
\u2013
\u2013
Balance at 31 December 2023
935,172
2,337,931
3,273,103
Exercisable at 31 December 2023
935,172
935,172
1,870,344
Share option exercise price
\u00a30.01
\u00a30.01
N/A
Weighted average remaining life
N/A
N/A
N/A
Mr Bruce left the business on 4 January 2024 and, as part of his termination arrangements, retained his 935,172 share options which had already vested.
Management Equity Plan (MEP)
During the year to 31 December 2022, Mr Myerson was also awarded share options under a Management Incentive Agreement (MIA) and Share Subscription and Bonus Agreement (SSBA), comprising 100 B1 shares of $0.01 each
and 100 B2 shares of $0.01 each. Following the changes in the issued share capital, as detailed in note 26, in the run up to the IPO, on 9 November 2022 these share options equated to 1,401,759 B1 shares of \u00a30.01 each and 420,528
B2 shares of \u00a30.01 each. Following the IPO Mr Myerson elected to retain these options but in so doing did not waive his right to receive the Aggregate Guaranteed Payment (AGP) of $10.0 million less any special bonus payments
since September 2021.
During the year to 31 December 2023, Mr Myerson elected to receive the 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 2023 was $3.0 million (2022: $6.2 million).
The share-based payment reserve of $15.5 million (2022: $4.9 million) reflects the opening balance of $4.9 million (2022: $nil) plus the charge of $12.9 million (2022: $0.6 million) for LTIPs plus the charge of $0.5 million
(2022: $7.3 million) for IPO-related share options less the cost of satisfying exercises during the year of $2.8 million (2022: $3.0 million).
", "dimensions": { "concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-441": { "value": "
33. Dividends
2023 2022
US$\u2019million US$\u2019million
First interim dividend of $0.132 per ordinary share announced 16 February 2023 and paid 9 March 2023
133.0
\u2013
Second interim dividend of $0.132 per ordinary share announced 23 August 2023 and paid 29 September 2023
133.0
\u2013
Total dividends paid during year ended 31 December 2023
266.0
\u2013
Third interim dividend of $0.132 per ordinary share announced 21 March 2024 and payable in April 2024 (not accrued in the 2023 results)
134.0
\u2013
Total dividends paid or payable relating to year ended 31 December 2023
400.0
\u2013
", "dimensions": { "concept": "ifrs-full:DisclosureOfDividendsExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } }, "fact-440": { "value": "
34. Subsequent events
On 6 March 2024 it was announced that EPL will be extended by a further year to 31 March 2029. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million.
On 19 March 2024, the North Sea Transition Authority sanctioned the extension of the licence on the Cambo field to 31 March 2026.
On 26 March 2024, the Group signed an exclusivity agreement between Eni S.p.A. and Ithaca Energy covering substantially all of Eni S.p.A.'s UK upstream assets, excluding Eni S.p.A. CCUS and Irish sea assets, under which Eni S.p.A.
has granted Ithaca exclusivity whilst a potential business combination is pursued. Under the terms of the proposed business combination Eni S.p.A. is anticipated to hold between 38% and 39% of the enlarged issued share capital of
Ithaca Energy following completion. If this progresses further, it will be subject to the issuance of both a Circular and a Prospectus and the related shareholder approvals and will also be subject to, amongst other things, regulatory approvals.
", "dimensions": { "concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory", "language": "en", "entity": "scheme:21380057TNFLXPXBIP34", "period": "2023-01-01T00:00:00/2024-01-01T00:00:00" } } } }