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"value": "1. Nature of operations Ithaca Energy plc (formerly Delek North Sea Limited (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 23 College Hill, London, United Kingdom, EC4R 2RP. During the year the Group consolidation was updated to include the immediate parent company and, as such, comparatives for 2021 have been presented accordingly.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGeneralInformationAboutFinancialStatementsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-330": {
"value": "1. Nature of operations Ithaca Energy plc (formerly Delek North Sea Limited (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 23 College Hill, London, United Kingdom, EC4R 2RP. During the year the Group consolidation was updated to include the immediate parent company and, as such, comparatives for 2021 have been presented accordingly. 2. Basis of preparation The consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standards 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. 3. Significant 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 IFRS) to fair value, including derivative instruments. Historical cost is generally based on the fair value consideration given in exchange for the assets. 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 Strong commodity markets in 2022, continuing robust commodity price backdrop despite lower prices during March 2023 and a well hedged portfolio over the next 12 months; \u2022 Reserves Based Lending (RBL) liquidity headroom of $475 million ($450 million drawn versus $925 million available), plus $210 million of cash as at 24 March 2023; and \u2022 Strong operational performance and well-diversified portfolio which has been further strengthened by the acquisitions of Siccar Point Energy and Summit as at 30 June 2022 and with Abigail coming online in October 2022. Cash flow forecast \u2013 base case assumptions: 2023 H1 2024 Average oil price $/bbl 77 72 Average gas price p/th 119 130 Average hedged oil price (including floor price for zero cost collars) $/bbl 69 77 Average hedged gas price (including floor price for zero cost collars) p/th 220 162 Owing to the on-going 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 there was no reasonably possible scenario that would result in the business being unable to meet its liabilities as they fell due. The Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 June 2024 to continue trading. In addition, reverse stress tests have been performed reflecting further reductions in commodity prices and production volumes, prior to any mitigating actions, to determine at what levels each would have to reach such that either lending covenants are breached or there is no liquidity headroom left. This stress test demonstrated that the likelihood of the fall in prices and production volumes required to cause a breach of covenants or liquidity issue, is considered sufficiently remote in the context of the mitigation strategies available to management. Mitigation strategies within the control of management include the reduction in uncommitted capital expenditure, variable opex savings in the low production scenario, the cancellation or deferral of future dividends and further potential to refinance the Group\u2019s borrowing arrangements. Based on their assessment of the Group\u2019s financial position in the period to 30 June 2024, 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. NOTES TO THE CONSOLIDATED 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 32. All intergroup transactions and balances have been eliminated on consolidation.
Subsidiaries are all entities, including structured 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 future. 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, on a net equity basis, 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 our 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 we cannot reduce
Scope 1 and Scope 2 emissions, we will invest in carbon offsets to achieve our 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 our 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 \u201ckey sources of estimation uncertainty\u201d 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 $83/bbl for Brent Crude and 86p/therm for UK NBP gas. The other areas of estimation uncertainty in this note and note 19 includes the impact on impairment headroom of a 20% downside in net revenues.
Management has concluded that this reduction is also reflective of amending its long-term commodity price assumptions to those that are in line with a range of transition paths consistent with the temperature goal of the Paris
climate change agreement, of holding the increase in the global average temperate at well below 2 degrees above pre-industrial levels and pursing efforts to limit the temperature to 1.5 degrees above pre-industrial levels. This
assessment is based on climate change scenarios currently available from the International Energy Agency and World Business Council for Sustainable Development.
Recoverable values used for impairment testing for all cash generating units (\u2018CGU\u2019s) include the estimated cost of UK carbon emissions allowances. 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
our 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 39, 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 2022, however no significant write-offs were identified.
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 twenty 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 2 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 $74 million. The risk in this area may increase if key assets within the group\u2019s existing exploration and appraisal assets proceed to development, as this is likely to significantly extend the life of the group\u2019s portfolio, in some cases to 2050 or beyond. On the basis that all other assumptions in the calculation remain the same, a 1.0% reduction in the applied discount rates used to assess the balance sheet decommissioning liability would result in an increase to the decommissioning provision of approximately $218 million (2021: $202 million). This change would be principally offset by a change in the value of the associated asset unless the asset in question is fully depreciated whereby the change in estimate would be recognised immediately through the statement of profit or loss. 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 cash generating unit (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 measured at the fair value of the consideration received or receivable and represents amounts receivable for products in the normal course of business, net of discounts, customs duties and sales taxes. 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 information 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 United States Dollars, which is the Group\u2019s presentation currency as well as the functional currency of the parent company and each of its subsidiaries. In preparing the financial
statements of the parent and its subsidiaries, transactions in currencies other than the entity\u2019s functional currency (foreign currencies) are recognised at the rates of exchange prevailing on the dates of the transactions. At each
reporting date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are
translated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated.
Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the
statement of profit or loss.
Exchange differences are recognised in profit or loss in the period in which they arise except for:
\u2022 Exchange differences on foreign currency borrowings relating to assets under construction for future productive use, which are included in the cost of those assets when they are regarded as an adjustment to interest costs on
those foreign currency borrowings;
\u2022 Exchange differences on transactions entered into to hedge certain foreign currency risks (see below under financial instruments/hedge accounting).
Financial instruments
All financial instruments are initially recognised at fair value on the statement of financial position. The Group\u2019s financial instruments consist of cash and cash equivalents, accounts receivable, deposits, accrued income, derivatives,
accounts payable, accrued liabilities, borrowings and contingent consideration. Under IFRS 9, with the exception of derivatives and contingent considerations, all financial instruments are recorded at amortised cost based on an
analysis of the business model and terms of financial assets. All financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the
respective financial instrument. 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
liability derecognised and the consideration paid and payable 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 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. Although the Group does not intend to trade its derivative financial instruments, they are required to be carried at fair value with the treatment of fair value movements
explained further below.
Transaction costs 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.
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 is recognised in profit or loss
immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship.
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, which is when the hedging relationships meet all of the following hedge effectiveness requirements: \u2022 There is an economic relationship between the hedged item and the hedging instrument; \u2022 The effect of credit risk does not dominate the value changes that result from that economic relationship; and \u2022 The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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. Note 30 and 31 set out details of the fair values of the derivative instruments used for hedging purposes. Movements in the hedging reserve in equity are detailed in note 29. Cash flow hedges 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 th e 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. 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.
Trade and other receivables
Trade receivables are recognised and carried at the original invoiced amount, less any provision for estimated irrecoverable amounts.
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.
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.
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 accrued income or \u2018overlift\u2019, included within deferred income 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.
Other receivables are carried at amortised cost using the effective interest method if the time value of money is significant. Gains and losses are recognised in the consolidated statement of profit or loss when the assets are
derecognised, modified or impaired. The Group\u2019s financial assets measured at amortised cost includes trade and other receivables and amounts due from related parties.
Trade and other payables
All other financial liabilities are initially recognised at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of
issue costs associated with the borrowing. After initial recognition, other financial liabilities are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any
issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised in interest and other income and finance costs respectively. This category of
financial liabilities included trade and other payables and finance debt.
Property, plant and equipment
Oil and gas expenditure \u2013 exploration and evaluation (E&E) assets
Geological and geophysical exploration costs are recognised as an expense 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 continued
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 internal 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. 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 Developing & Producing (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. Impairment For impairment review purposes the Group\u2019s oil and gas assets are aggregated into cash-generating units (CGUs) in accordance with IAS 36. A review is carried out 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. 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 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. 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 year Computer and office equipment 3 years Furniture and fittings 5 years Borrowings All interest-bearing loans and other borrowings with banks are initially recognised at fair value net of directly attributable transaction costs. After initial recognition, interest-bearing loans and other borrowings are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium. 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. Loan origination fees are capitalised and amortised over the term of the loan. 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. Senior notes are measured at amortised cost. 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 & 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. 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. Settlement of contingent and deferred considerations are recorded as investing outflows in the cash flow statement. Deferred consideration is measured at amortised cost. 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. The Group recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. 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 and other long-term employee benefits
A liability is recognised for benefits accruing to employees in respect of wages and salaries, 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. 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. Liabilities recognised in respect of
other long-term benefits are measured at the present value of the estimated future cash outflows expected to be made by the Group in respect of services provided by employees up to the reporting date.
Changes in accounting pronouncements
The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2021 to 31 December 2022.
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 new and revised IFRS Standards that have been issued but are not yet effective.
IFRS 17 Insurance Contracts
Amendments to IAS 1 Classification of Liabilities as Current or Non-current
Amendments to IAS 1 and IFRS Practice Statement 2 Disclosure of Accounting Policies
Amendments to IAS 8 Definition of Accounting Estimates
Amendments to IAS 12 Deferred Tax related to Assets and Liabilities arising from a Single Transaction
Amendments to IFRS 16 Lease Liability in a Sale and Leaseback
Amendments to IAS 1 Non-current Liabilities and Covenants
The Company does not expect that the adoption of the Standards and 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
The following are the critical judgements, apart from those involving estimations (which are presented separately below), that the directors have made in the process of applying the Group\u2019s accounting policies and that have the
most significant effect on the amounts recognised in financial statements.
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. 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. Although decommissioning costs are expected to be incurred over the next 40 years it is anticipated that approximately 33% of the liability will be paid within the next five years. A nominal discount rate of 4.25% (2021: 2.5%) is used to discount the estimated costs. The inflation rate applied to discount the estimated costs is 2.0% (2021: 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 variation in this discount rate of 1% would change the decommissioning liabilities by approximately $218 million (2021: $202 million), 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. Commodity derivatives 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 $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 2022 of $188 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: 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 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.
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, 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, 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 (see critical accounting judgement below). 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 2022, 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 $24 million.
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 $24 million de-recognition 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.
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.
The sensitivity of the elements of contingent consideration linked to the oil price is disclosed in note 25. It is not practical to provide sensitivities to other specific assumptions given the multiple contingent events and
assumptions\u202finvolved.
Critical accounting judgements Acquisitions In the periods presented, the Group has made a number of acquisitions \u2013 see note 17 for further details of the final/provisional purchase price allocation, including the assets and liabilities acquired, the goodwill/gain on bargain purchase arising on acquisition and details of the contingent consideration payable. The acquisitions were accounted for as business combinations under IFRS 3. The assets and liabilities identified in the purchase price allocation include oil & gas assets, decommissioning liabilities, deferred tax assets and liabilities, derivatives and working capital. The total consideration payable includes both amounts paid at completion of each of the acquisitions and further amounts which are contingent on certain events taking place. Judgements are required to be made regarding the future value of associated contingent consideration, as further described above. The calculation of the fair value of the oil and gas assets acquired requires the Group to estimate the future cash flows expected to arise from the CGUs in the acquired business using discounted cash flow models. Key assumptions and estimates include: commodity prices, discount rates and oil and gas reserves estimates. See above estimates in the impairment of oil and gas assets and goodwill sections and estimate in the oil and gas reserves section for further details regarding these assumptions. In addition, the Group has considered the value that a market participant would prescribe to prospective resources in determining both the fair value of the oil & gas assets acquired and the contingent consideration recognised. In determining the value of the deferred tax asset recognised on acquisition, the Group has made assumptions in respect of the amount of tax losses brought forward which will be available to offset against future taxable profits of the Group. Specifically, in respect of the MOGL acquisition, assumptions have been made with regards to the group relief claims the seller is entitled to make relating to pre-completion periods (pre 4 February 2022) which would reduce the losses available to the Group, and the quantum of such claims. The provisional deferred tax asset recognised by the Group assumes full utilisation of the losses held in MOGL and therefore a change in this assumption could result in a change in the deferred tax asset recognised on the balance sheet on acquisition, which would be recognised through profit and loss in the period of this change. Further, in assessing the value of the deferred tax asset recognised in the MOGL and Siccar Point Energy acquisitions, the Group has made assumptions regarding future restructuring within the Group, therefore a change in these assumptions could result in a change in the deferred tax asset recognised. Fair value of derivative instruments 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. 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. 5. Revenue 2022 US$\u2019000 2021 US$\u2019000 Oil sales 1,692,697 856,492 Gas sales 1,348,212 724,527 NGL sales 75,445 52,466 Other income 40,617 32,742 Realised losses on oil derivative contracts (211,636) (48,833) Put premiums on oil derivative instruments (14,629) (27,179) Realised losses on gas derivative contracts (289,877) (147,348) Put premiums on gas derivative instruments (42,347) (14,627) 2,598,482 1,428,240 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 one customer exceeds 10% of the Group\u2019s consolidated revenue arising from hydrocarbon sales for the year ended 31 December 2022 (31 December 2021: one), representing $2,436 million for the year ended 31 December 2022 (2021: $1,437 million). Revenue from contracts with customers derives largely from customers within a single geographical region, being the United Kingdom. Revenue from contracts with customers out with the United Kingdom is immaterial and is therefore not disclosed separately. 6. Cost of sales 2022 US$\u2019000 2021 US$\u2019000 Movement in oil and gas inventory (130,295) 6,970 Operating costs (547,795) (424,046) Royalties (11,287) (6,192) Depreciation on right-of-use assets (note 15) (37,438) (5,613) Depletion, depreciation and amortisation (note 15) (625,509) (450,300) (1,352,324) (879,181) Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds a 100% interest in the Stella and Harrier fields. 7. Administrative expenses 2022 US$\u2019000 2021 US$\u2019000 General and administrative (27,693) (15,180) Share-based payment charge (note 33) (14,069) \u2013 Transaction costs (46,089) \u2013 (87,851) (15,180) Transactions costs in 2022 relate to the acquisitions of MOGL, Summit Exploration and Production Limited (Summit) and Siccar Point Energy entities, and costs incurred in connection to the IPO. Further details on the acquisitions can be found in note 17. The total employee benefit expenses which is either capitalised or included in cost of sales and administrative expenses are noted below. Employee benefit expenses 2022 US$\u2019000 2021 US$\u2019000 Wages and salaries (81,017) (62,546) Social security costs (9,902) (7,132) Pension costs (8,298) (7,505) (99,217) (77,183) The average number of employees for the year was as follows: 2022 2021 Onshore and administrative 268 251 Offshore 249 217 517 468 Audit fees 2022 US$\u2019000 2021 US$\u2019000 Fees payable to the current Company\u2019s auditor for audit of the Company\u2019s financial statements (1,095) (685) Fees payable to the previous Company\u2019s auditor for audit of the Company\u2019s financial statements \u2013 (35) Audit of the Company\u2019s subsidiaries pursuant to legislation (279) (62) Non-audit fees provided by the current auditors (4,707) \u2013 Non-audit fees provided by the previous auditors \u2013 (236) (6,081) (1,018) Non-audit fees provided by the current auditors for the year ended 31 December 2022 comprise audit-related assurance services of $170k, other assurance services of $990k and other non-audit services of $3,547k, with the latter two captions relating to reporting accountant workstreams in relation to the IPO. 8. Other gains and losses 2022 US$\u2019000 2021 US$\u2019000 Loss on financial instruments (278) (453) Fair value (losses)/gains on contingent consideration (4,295) 8,250 Net foreign exchange (4,856) (3,970) (9,429) 3,827 9. Net finance costs 2022 US$\u2019000 2021 US$\u2019000 Bank interest and charges (58,317) (41,372) Senior notes interest (61,537) (74,677) Loan fee amortisation (6,418) (35,343) Interest on lease liabilities (note 24) (3,852) (367) Interest on related party loan (note 32) (17,924) (48,277) Accretion (56,511) (38,348) Realised gains/(losses) on interest derivative contracts (note 29) 851 (7,276) Interest income 695 11 Other \u2013 (4,487) (203,013) (250,136) There was no interest capitalised into qualifying assets in either the year to 31 December 2022 or the year to 31 December 2021. 10. Earnings per share The calculation of basic earnings per share is based on the profit after tax and the weighted average number of ordinary shares in issue during the year. Basic and diluted earnings per share are calculated as follows: 2022 US$\u2019000 2021 US$\u2019000 Earnings for the year: Earnings for the purpose of basic earnings per share 1,031,532 425,989 Effect of dilutive potential ordinary shares \u2013 \u2013 Earnings for the purpose of diluted earnings per share 1,031,532 425,989 Number of shares (million) Weighted average number of ordinary shares for the purpose of basic earnings per share 1 1,005.2 1,005.2 Dilutive potential ordinary shares 5.0 2.1 Weighted average number of ordinary shares for the purpose of diluted earnings per share 1,010.2 1,007.3 Earnings per share (cents) Basic 102.6 42.4 Diluted 102.2 42.3 1 In accordance with IAS 33 paragraph 64, following the issue of bonus shares (900,073,953) and new shares (105,000,000) in connection to the IPO, the weighted average number of shares in 2022 and 2021 have been retrospectively restated to reflect the number of shares post IPO. 11. Trade and other receivables Current 2022 US$\u2019000 2021 US$\u2019000 Trade receivables 31,906 18,918 Other receivables 14,210 25,420 Joint venture receivables 99,800 79,917 Accrued income 214,078 104,035 359,994 228,290 The Group regularly monitors all customer receivable balances outstanding in excess of 90 days for expected credit losses. The Group applies a simplified approach in calculating Expected Credit Losses (ECLs) as allowed under IFRS 9. Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, the economic environment and the Group\u2019s historical credit loss experience. Substantially all trade and other receivables are current, being defined as less than 90 days and as such no ECLs have been recognised in the current or prior year as the ECL is considered immaterial. Non-current 2022 US$\u2019000 2021 US$\u2019000 Decommissioning reimbursement 162,710 152,184 Current 2022 US$\u2019000 2021 US$\u2019000 Decommissioning reimbursement 38,115 94,640 The decommissioning reimbursement represents the equal and opposite of decommissioning liabilities (note 23), net of tax, associated with the Heather and Strathspey fields and relates to a contractual agreement as part of the CNSL acquisition. As part of the terms of the CNSL acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL in relation to these interests. As the payment is virtually certain this has been accounted for under IAS 37 as a reimbursement asset. 12. Prepaid expenses and decommissioning securities Current 2022 US$\u2019000 2021 US$\u2019000 Prepayments 7,415 8,524 Decommissioning securities 1,640 2,012 9,055 10,536 13. Inventories Current 2022 US$\u2019000 2021 US$\u2019000 Hydrocarbon inventories/underlift 87,563 115,743 Materials inventories 124,755 89,374 Provision for obsolete materials inventory (35,437) (27,498) 176,881 177,619 Non-current 2022 US$\u2019000 2021 US$\u2019000 Hydrocarbon inventories \u2013 532 14. Exploration and evaluation assets US$\u2019000 At 1 January 2021 70,589 Additions 45,922 Write offs/relinquishments (156) At 31 December 2021 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 775,773 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 $14.3 million being expensed in the year to 31 December 2022 (2021: $0.2 million). The transfers from exploration and evaluation assets to development and production assets relates to the Abigail and Jade South wells. The write offs/relinquishments includes $5.3 million of impairment relating to decommissioning revisions. The principal exploration and evaluation assets at 31 December 2022 are Cambo and Rosebank which formed part of the Siccar acquisition (see note 17). 15. Property, plant and equipment Right-of-use operating assets US$\u2019000 Development and production assets US$\u2019000 Other fixed assets US$\u2019000 Total US$\u2019000 Cost At 1 January 2021 13,139 5,496,465 18,856 5,528,460 Additions 2,512 341,713 21,437 365,662 Disposals (6,441) \u2013 \u2013 (6,441) At 31 December 2021 and 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 98,927 7,112,652 45,912 7,257,491 Depletion, depreciation, amortisation and Impairment At 1 January 2021 (6,257) (2,930,215) (8,275) (2,944,747) Depletion, depreciation and amortisation charge for the year (5,613) (444,751) (5,549) (455,913) Disposals 6,441 \u2013 \u2013 6,441 Impairment reversal (note 19) \u2013 465,271 \u2013 465,271 At 31 December 2021 and 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 (42,867) (3,555,656) (24,072) (3,622,595) Net book value at 31 December 2021 3,781 2,928,483 26,469 2,958,733 Net book value at 31 December 2022 56,060 3,556,996 21,840 3,634,896 The transfers from exploration and evaluation assets to development and production assets relates to the Abigail and Jade South wells. At the point of transfer these assets were tested for impairment and none was found. Other fixed assets includes buildings, computer equipment, office equipment and furniture and fittings. 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: Block Licence Field/Discovery Name Operator Group Net % Interest 2022 2021 9/11c P.979 Mariner Equinor UK Limited 8.89% 0.00% 9/11b P.726 Mariner Equinor UK Limited 8.89% 0.00% 30/2c P.672 Jade Chrysaor Petroleum Company UK Limited 15.50% 6.64% 22/30c and 29/5c P.666 Elgin-Franklin TotalEnergies E&P UK Limited 6.09% 1.95% 15/29b P.590 Callanish Chrysaor Production (UK) Limited 20.00% 20.00% 204/25a P.559 Schiehallion BP Exploration Operating Company Limited 35.30% 0.00% 204/19b and 204/20b P.556 Suilven Ithaca SP E&P Limited 50.00% 0.00% 29/5b P.362 Elgin-Franklin TotalEnergies E&P UK Limited 6.09% 1.95% 21/4a P.347 Callanish Chrysaor Production (UK) Limited 13.70% 13.70% 16/27b P.345 Britannia Chrysaor Production (UK) Limited 35.75% 35.75% 9/11a P.335 Mariner Equinor UK Limited 8.89% 0.00% 13/22a P.324 Captain Ithaca Energy (UK) Limited 85.00% 85.00% 22/18a P.292 Arbroath, Arkwright, Carnoustie, Wood Repsol Sinopec Resources UK Limited 41.03% 0.00% 22/17s, 22/22a and 22/23a P.291 Arbroath, Arkwright, Brechin, Carnoustie, Cayley, Shaw Repsol Sinopec Resources UK Limited 41.03% 0.00% 23/26b P.264 Erskine Ithaca Energy (UK) Limited 50.00% 56.67% 9/11d and 9/12b P.2508 Mariner Equinor UK Limited 8.89% 0.00% 22/1b P.2373 F Block (Fotla and Fortriu) Ithaca Oil and Gas Limited 60.00% 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% 0.00% 16/26a P.213 Alba Ithaca Oil and Gas Limited 36.67% 36.67% 16/26a P.213 Britannia Ithaca MA Limited 33.17% 33.17% 16/26a P.213 N/A Ithaca Oil and Gas Limited 21.85% 21.85% 3/7a P.203 Columba E CNR International (UK) Limited 20.00% 0.00% 3/8a and 3/8a P.199 Columba B/D CNR International (UK) Limited 5.60% 0.00% Group Net % Interest Block Licence Field/Discovery Name Operator 2022 2021 22/30b P.188 Elgin-Franklin TotalEnergies E&P UK Limited 6.09% 3.04% 21/20a P.185 Cook Ithaca Energy (UK) Limited 61.35% 61.35% 8/15a P.1758 Mariner Equinor UK Limited 8.89% 0.00% 29/10b P.1665 Abigail Ithaca Energy (UK) Limited 100.00% 50.00% 30/7b P.1589 Jade Chrysaor Petroleum Company UK Limited 25.50% 9.97% 30/1f P.1588 Vorlich Ithaca Energy (UK) Limited 100.00% 100.00% 205/2a P.1272 Rosebank Equinor UK Limited 20.00% 0.00% 205/1a P.1191 Rosebank Equinor UK Limited 20.00% 0.00% 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 70.00% 0.00% 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.103 Britannia Chrysaor Production (UK) Limited 33.03% 33.03% 21/5a P.103 Enochdhu Chrysaor Production (UK) Limited 50.00% 50.00% 204/9a and 204/10a P.1028 Cambo Ithaca SP E&P Limited 70.00% 0.00% 213/26b and 213/27a P.1026 Rosebank Equinor UK Limited 20.00% 0.00% 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% 0.00% 22/17s, 22/22a and 22/23a P.019 Godwin, Montrose Repsol Sinopec Resources UK Limited 41.03% 0.00% 30/6a and 29/10a P.011 Stella/Harrier Ithaca Energy (UK) Limited 100.00% 100.00% 30/11a and 30/12d P.1820 Isabella Total Energies E&P North Sea UK Limited 10.00% 10.00% 204/8, 204/9c, 204/10c, 204/13, 204/14d P.2403 Tornado Ithaca SP E&P Limited 50.00% 0.00% and 204 /15 17. Business combinations The fair values of the identifiable assets and liabilities as at the acquisition dates were: MOGL 2022 US$\u2019000 Siccar 2022 US$\u2019000 Summit 2022 US$\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 cashflows relating to acquisition 62,818* (926,708) (100,563) * Net cashflows relating to the MOGL acquisition includes a $7 million deposit paid in the year ended 31 December 2021. The fair value of the financial assets includes trade and other receivables with a fair value of $78.8 million and an equal gross contractual value. 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 (\u201cSPA\u201d) 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\u202fJanuary\u202f2022 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 calculated at the acquisition date uses the same assumptions as set out in the critical accounting judgements section of note 3 and is subsequently revalued at the year end date. From the date of acquisition, the MOGL assets have contributed $316 million of revenue and $199 million of profit before tax in 2022. Had the acquisition occurred on 1 January 2022, the MOGL assets would have contributed $343\u202fmillion of revenue and $224 million of profit before tax for the 2022 financial year. 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 unable 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 20.00%, Cambo 70.00% and Tornado 50.00%) 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\u202fterms of the SPA. The contingent consideration calculated at the acquisition date uses the same assumptions as set out in the critical accounting judgements section of note 3 and is subsequently revalued at the year end date. From the date of acquisition, the Siccar Point Energy assets have contributed $184 million of revenue and $90 million of profit before tax in 2022. Had the acquisition occurred on 1 January 2022, the Siccar Point Energy assets would\u202fhave contributed $337 million of revenue and a $128 million loss before tax for the 2022 financial year. 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 which were unable to be utilised by Siccar Point Energy, 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 $200m 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 $25.6m 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 is 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 $62m 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. From the date of acquisition, the Summit assets have contributed $52 million of revenue and $38 million of profit before tax in 2022. Had the acquisition occurred on 1 January 2022, the Summit assets would have contributed $83\u202fmillion of revenue and $32 million of profit before tax for the 2022 financial year. There are no contingent consideration arrangements under the Sale and Purchase Agreement of the Summit assets. Mitsui On 30 November 2021, the Group completed the acquisition of an additional 13.3% interest in the Alba field from Mitsui E&P UK Limited. The acquisition comprised property, plant and equipment of $22 million, a working capital creditor of $11 million and a decommissioning provision of $55 million. This resulted in a reverse consideration being paid to the Group, as such the consideration owed from Mitsui to the Group was $55 million. No contingent liabilities have been acquired on the business combinations detailed above. The fair values of the oil and gas assets and the intangible assets acquired have been determined using valuation techniques based on discounted cash flows using forward curve commodity prices and estimates of long-term commodity prices reflective of market conditions at each completion date, a discount rate based on observable market data and cost and production profiles generally consistent with the proved and probable reserves acquired with each asset (see note 19 for further details). The decommissioning liabilities recognised have been estimated based on operator cost estimates with reference to observable market data. 18. Goodwill 2022 US$\u2019000 2021 US$\u2019000 Balance at 1 January 722,075 722,075 Additions (note 17) 61,773 \u2013 Balance at 31 December 783,848 722,075 The goodwill is not tax deductible on any of the acquisitions. The opening goodwill of $722 million relates to historic business combinations. The goodwill on acquisition in the current period relates to the Summit acquisition, as detailed in note 17. Annual impairment tests were performed. The review was carried out on a fair value less cost of disposal basis using risk adjusted cash flow projections from the approved business plans including the same commodity prices, life of field cost profiles and production volumes used for impairment of oil and gas assets (see note 19), discounted at a post-tax discount rate of 10.9%. Assumptions and estimates in the Group impairment models are detailed in note 3. The CGU for the purposes of the goodwill test is the North Sea i.e. the entire Group portfolio of oil and gas assets which is consistent with the operating segment view of the business. The fair value estimate is categorised as level 3 in the fair value hierarchy. 19. Impairment (charge)/reversal on oil and gas assets 2022 US$\u2019000 2021 US$\u2019000 D&P assets (30,700) 465,271 E&E assets (1,867) \u2013 Contingent consideration reversal 1,100 \u2013 North Sea oil and gas assets (31,467) 465,271 The impairment charge on D&P assets of $30.7 million in 2022 reflect revisions in decommissioning provisions, principally on fields that are no longer producing. An impairment review was 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 (\u201cEPL\u201d) 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 discount rate assumption Price assumptions (nominal) 2023 2024 2025 2026 2027* Oil 10.90% $89/bbl $84/bbl $83/bbl $83/bbl $83/bbl Gas 10.90% 315p/therm 211p/therm 99p/therm 86p/therm 86p/therm * post 2027 an annual 2% increase is applied to the price assumption 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 a post-tax impairment of PP&E of $13 million at 31 December 2022. An increase of 1% in the discount rate assumption would not result in a post-tax impairment of PP&E. There would be no impairment of goodwill. A\u202fdecrease in discount rate or an increase in forecast revenues would have no material impact on post-tax carrying amounts. 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. During 2021, the Group recorded a $465 million pre-tax impairment reversal relating to oil and gas assets. The review was driven by higher commodity price forward curves and was carried out on a fair value less costs of disposal basis, resulting in pre-tax reversal of $397.3 million on Stella, $28.8 million on Alba and $33 million on Pierce, with related post-tax recoverable amounts of $565 million, $77 million and $120\u202fmillion respectively. The remaining reversal of $6 million relates to revisions to decommissioning estimates for assets which have been fully impaired. The following assumptions were used at Q4 2021 in developing the cash flow model and applied over the expected live of the respective fields: Post-tax discount rate assumption Price assumptions (nominal) 2022 2023 2024 2025 2026 Oil 9.50% $76/bbl $69/bbl $71/bbl $72/bbl $74/bbl Gas 9.50% 164p/therm 99p/therm 68p/therm 61p/therm 56p/therm Estimated production volumes and cash flows up to the date of cessation of production on a field by field basis, including operating and capital expenditure, are derived from the approved business plans and third party reports. 20. Borrowings 2022 US$\u2019000 2021 US$\u2019000 Current Amounts owed to related parties (note 32) \u2013 (437,076) \u2013 (437,076) Non-current RBL facility (600,000) (350,000) Senior unsecured notes (625,000) (625,000) Unamortised long-term bank fees 7,591 13,214 Unamortised long-term senior notes fees 3,678 7,170 Total debt (1,213,731) (954,616) Accrued interest on borrowings is included within accruals (note 22). Adjusted net debt 2022 US$\u2019000 2021 US$\u2019000 Total debt 1,213,731 1,391,692 Less cash and cash equivalents (253,822) (44,849) Adjusted net debt 959,909 1,346,843 Adjusted net debt does not include lease liabilities. Amounts owed to related parties In November 2019 the Group issued interest-free capital loan notes worth a nominal value of $392 million to a related Group undertaking, DKL Energy Limited. At the date of issuance, the capital loan notes were due for repayment no later than May 2022, after which point these were repayable on demand. On initial recognition, in November 2019, the capital loan notes were recorded at a fair value of $278m estimated based on a 15% market rate of interest. The difference between the two was recorded as a $114 million capital contribution (see note 26). The capital contribution was fully unwound as a result of a capital reduction in preparation for the IPO. Capital loan notes of $182\u202fmillion were waived (see note 32) with the balance of $210 million being repaid out of the proceeds of the IPO. The waived loan of $182 million has been capitalised as a Capital Contribution Reserve (see note 26). Subordinated loan In November 2019, the Group issued a subordinated loan note worth $198 million to the same Group undertaking, DKL Energy Limited. The interest terms up to May 2021 matched those of an external loan with BNP Paribas entered into by DKL Energy on which a margin ranging from 6.5% to 11.5% on LIBOR was charged. Subsequent to repayment of the BNP Paribas loan by DKL Energy in May 2021, the tracker loan note was interest free. The tracker loan note was due for repayment at the date of issuance no later than May 2022, after which it was repayable on demand. The Group prepaid $120m of the tracker loan note in 2020 and $15 million in 2021. The remaining balance was\u202frepaid out of proceeds of the IPO. Reserves Based Lending (RBL) facility During 2019, the Group\u2019s RBL facility size was increased to $1,650 million and its maturity was extended to April 2024, simultaneously an existing $300 million Term Loan was retired. The effective interest rate of the facility was 4.96%. Loan fees of $26.7 million relating to the RBL were capitalised in 2019 and amortised over the remaining life of the loan. In July 2021, the Group completed a further 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 2022, due to the NPV cap described in the covenants section below, the total availability was $925 million, of which $600 million was drawn down, leaving a further amount of $325 million being available for drawdown. Loan fees of $15.2 million relating to the RBL were capitalised and will be amortised over the term of the loan, $7.6 million remains to be amortised as at 31 December 2022. Following the refinancing $18.1 million of un-amortised fees were expensed to the statement of profit or loss in 2021, included within loan fee amortisation, relating to the previous RBL facility. 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 2022 was $6,760\u202fmillion (2021: $4,732 million). Senior notes During July 2019, the Group issued $500 million 9.375% senior unsecured notes due for repayment in July 2024 with interest payable semi-annually. Loan fees of $14.3 million relating to the senior notes were capitalised on issuance and amortised over the remaining life of the loan. In July 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, $3.7 million remains to be amortised as at 31 December 2022. Following the refinancing, $6 million of un-amortised fees were expensed, to the statement of profit or loss in 2021, included within loan fee amortisation relating to the previous senior notes. 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 redeemed on 12th October 2022 and there is no remaining balance as at 31 December 2022. Covenants in relation to these senior notes are detailed below. Covenants The Group is subject to financial and operating covenants related to the RBL facility. There are no covenants associated with amounts owed to related parties. 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 $625m 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: incur additional debt; 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 net debt to EBITDAX shall be less than 3.5:1. \u2018Net debt\u2019 referred to is not an IFRS measure. The Company uses net debt as a measure to assess its financial position. Net debt comprises amounts outstanding under the Company\u2019s RBL facility and senior notes, less cash and cash equivalents. Subordinated debt of $250m from Delek Group Limited which was repaid on 3 August 2021 is a treated as a parent company loan; \u2022 Total projected sources of funds must exceed the total projected uses of funds for the following 12 month period (or a longer period to first production from development, if applicable); \u2022 The ratio of the net present value of cash flows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1; and \u2022 The ratio of the net present value of cash flows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1. The Group was in compliance with all financial covenants of the RBL in all periods presented. 21. Changes in liabilities arising from financing activities * 2022 US$\u2019000 2021 US$\u2019000 At 1 January (1,395,048) (1,855,773) Cash flows 377,198 650,736 Acquisitions (200,000) \u2013 Other (47,613) (190,011) At 31 December (1,265,463) (1,395,048) * being interest bearing loans, lease liabilities and interest rate derivatives. Other movement comprises mainly finance costs, capital contribution and related imputed interest. 22. Trade and other payables 2022 US$\u2019000 2021 US$\u2019000 Trade payables (14,917) (13,901) Amounts owed to parent (note 32) \u2013 (43,408) Hydrocarbon amounts owed to joint ventures/overlift (124,365) (42,944) Other payables (185,720) (187,655) Accruals (299,604) (139,818) Deferred income (86,806) (56,542) (711,412) (484,268) The Directors consider the carrying values of trade and other payables to approximate the fair value. Other payables mainly comprises VAT liabilities and amounts owed due to production adjustments. Hydrocarbon amounts owed to joint ventures comprises hydrocarbon inventory overlift owed to partners. 23. Decommissioning liabilities 2022 US$\u2019000 2021 US$\u2019000 Balance at 1 January (1,641,489) (1,416,236) Business combination additions (390,530) (55,429) Accretion (52,592) (42,502) Additions and revisions to estimates 298,564 (175,190) Decommissioning provision utilised 65,507 47,868 Balance, end of period (1,720,540) (1,641,489) Current Balance, beginning of period (94,640) (28,836) Balance, end of period (146,829) (94,640) Non-current Balance, beginning of period (1,546,849) (1,387,400) Balance, end of period (1,573,711) (1,546,849) 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 discount rate of 4.25 percent (31 December 2021: 2.5 percent) and an inflation rate of 2.0 percent (31 December 2021: 2.0 percent) 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 2022 and 2021 were due to changes in both cost estimates and discount rate\u202fassumptions. The estimated 2023 decommissioning spend of $147 million has been treated as a current liability as at 31 December 2022 (2021: $95 million). While the Group currently expects to incur decommissioning costs over the next 40\u202fyears, we anticipate that approximately 33% of the liability will be paid within the next five years. 24. Lease liabilities Current 2022 US$\u2019000 2021 US$\u2019000 Lease liability (41,637) (3,211) Non-Current 2022 US$\u2019000 2021 US$\u2019000 Lease liability (17,221) (278) The following table sets out a maturity analysis of lease payments, showing the undiscounted lease payments to be paid after the reporting date. All lease liabilities are fully payable within two years from 31 December 2022. 2022 US$\u2019000 2021 US$\u2019000 Less than one year (44,257) (2,094) One to two years (17,439) (1,617) Total undiscounted lease payments (61,696) (3,711) Future finance charges and other adjustments 2,838 222 Lease liabilities in the financial statements (58,858) (3,489) 2022 US$\u2019000 2021 US$\u2019000 At 1 January (3,489) (6,992) Additions (89,717) \u2013 Interest (3,852) (367) Payments 38,200 3,870 At 31 December (58,858) (3,489) Current (41,637) (3,211) Non-current (17,221) (278) (58,858) (3,489) The office lease was repaid in full during 2021. The addition in the year to 31 December 2022 relates to the Pioneer rig lease currently utilised on the Captain EOR project. The incremental borrowing rate applied to the lease is 6.07%. If the Company were to terminate the use of the Pioneer rig early then termination fees would apply, escalating to 75% of total expected costs if within 1 month prior to commencement date of planned works. Remuneration for work performed up to the date of termination, together with costs relating to demobilisation of the drilling unit to the demobilisation port would also be due. Amounts recognised in profit and loss related to leases is detailed in notes 6 and 9. 25. Contingent and deferred consideration Current 2022 US$\u2019000 2021 US$\u2019000 Contingent consideration (101,559) \u2013 Petrofac deferred consideration (6,121) (49,806) (107,680) (49,806) Non-current 2022 US$\u2019000 2021 US$\u2019000 Contingent consideration (157,337) (19,480) Petrofac deferred consideration \u2013 (5,804) MOGL deferred consideration (61,783) \u2013 (219,120) (25,284) 2022 US$\u2019000 2021 US$\u2019000 Cash flows relating to contingent and deferred considerations (66,132) \u2013 Movement in contingent consideration and deferred consideration is as follows: 2022 US$\u2019000 2021 US$\u2019000 At 1 January (75,090) (67,114) Business combinations (note 17) (304,846) (13,530) Utilisation 66,132 \u2013 Reversal 1,100 \u2013 Accretion (9,801) (2,696) Changes in fair value (4,295) 8,250 At 31 December (326,800) (75,090) Cash outflows in the year ended 31 December 2022 of $66.1 million are in relation to the consideration payable on Petrofac GSA transaction and three quarterly payments in consideration to the MOGL oil price trigger. Petrofac The Petrofac deferred consideration relates to the completion of the GSA transaction in December 2018 and is payable over a period from 2020 to 2023 and is discounted to reflect the time value of money. Interest is payable at 5% on $15 million of the consideration. As part of the GSA transaction, Petrofac had the opportunity to earn up to an additional sum dependent on the future performance of the Stella and Harrier fields. $51.6 million was paid during 2022 in accordance with the Petrofac SPA. 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 2022, discounted at 4.25% was $128 million. The total undiscounted potential consideration as\u202fat 31 December 2022 is $241 million. The MOGL deferred consideration of $61.8 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 an interest in Siccar 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 2022, discounted at 4.25% was $102 million. The total undiscounted potential consideration as at 31 December 2022 is $362 million. Others $2.5 million of the non-current contingent consideration balance relates to the acquisition of the Vorlich field, with a remaining payment of $3.0 million due upon defined production criteria being met. $6.4 million relates to Yeoman/Marigold, with a remaining unrisked payment of $11.0 million contingent on achieving FDP and a further $6 million unrisked on certain production criteria being met. During the year ended 31 December 2022, further consideration of $6.4 million was recognised as an additional payable, resulting in $19.9 million (2021: $13.1 million) on Strathspey in accordance with the Sale and Purchase\u202fagreement. Revaluation of contingent consideration in the year to 31 December 2022 resulted in an increase of $4.3 million (2021: decrease of $8.3 million). 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, resulting in a reduction of $26.4 million or an equal and opposite increase to the contingent consideration respectively (2021: $nil). 26. Reserves (a) Issued share capital The issued share capital is as follows: Number of common shares Amount US$\u2019000 At 31 December 2021 1,001 1 At 31 December 2022 1,006,564,976 11,445 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 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, $0.01 B1 share and 0.01 B2 share to \u00a30.01 A ordinary shares 87,087 (12) (12) \u2013 87,063 Bonus Issue of new \u00a30.01 A shares 898,131,843 \u2013 \u2013 \u2013 898,131,843 Bonus Issue of new \u00a30.01 B1 shares \u2013 1,401,670 \u2013 \u2013 1,401,670 Bonus Issue of new \u00a30.01 B2 shares \u2013 \u2013 420,440 \u2013 420,440 Conversion of \u00a3 0.01 A ordinary shares, \u00a30.01 B1 shares and \u00a30.01 B2 shares to \u00a30.01 ordinary shares (898,219,931) (1,401,758) (420,528) 900,042,217 \u2013 Bonus issues of \u00a30.01 ordinary shares \u2013 \u2013 \u2013 120,000 120,000 Issue of new \u00a30.01 ordinary shares on IPO \u2013 \u2013 \u2013 105,000,000 105,000,000 Issue of new \u00a30.01 ordinary shares on exercise of share options \u2013 \u2013 \u2013 1,402,759 1,402,759 Ordinary shares of \u00a30.01 each at 31 December 2022 \u2013 \u2013 \u2013 1,006,564,976 1,006,564,976 (b) Share premium 2022 US$\u2019000 2021 US$\u2019000 Balance at 01 January 634,658 634,658 Share premium cancellation (634,658) \u2013 Addition 293,712 \u2013 Balance at 31 December 293,712 634,658 Addition during the year represents the difference between the nominal value of share \u00a30.01 and IPO price of \u00a32.50 per share (net of share issues expenses). (c) Capital contribution reserve (note 20) 2022 US$\u2019000 2021 US$\u2019000 Balance at 01 January 114,000 114,000 Capital reduction (114,000) \u2013 Addition 181,945 \u2013 Balance at 31 December 181,945 114,000 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 $181.9m has been capitalised as Capital Contribution Reserve as per the requirements of IFRS 9. (d) Share-based payment reserve 2022 US$\u2019000 2021 US$\u2019000 At 31 December 4,920 \u2013 27. Taxation 2022 US$\u2019000 2021 US$\u2019000 Current tax Current corporation tax (charge)/credit (185,946) 14,863 Current corporation tax credit \u2013 prior year 1,839 3,815 Total current tax (charge)/credit (184,107) 18,678 Deferred tax Adjustment in respect of prior period (641) (1,215) Group tax charge in consolidated statement of profit or loss (1,013,817) (386,767) Group tax (charge)/credit in consolidated statement of other comprehensive income (200,455) 194,632 Total deferred tax charge (1,214,913) (193,350) Deferred Petroleum Revenue Tax Deferred PRT (charge)/credit in statement of profit or loss (10,432) 32,154 Total Tax charge through consolidated statement of profit or loss (1,208,997) (337,150) The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows: 2022 US$\u2019000 2021 US$\u2019000 Accounting profit before tax 2,240,529 763,139 At tax rate of 40% (2021: 40%) (896,211) (305,256) Non-deductible expense (53,548) (71,996) Recognition of non-taxable gain on bargain purchase 534,069 \u2013 Financing costs not allowed for SCT (1,958) (2,499) Ring Fence Expenditure Supplement 155,113 11,313 Deferred tax effect of investment allowance (20,615) 9,735 Over provided in prior years 1,198 2,602 Net deferred PRT (6,259) 19,293 Deferred tax on EPL (766,489) \u2013 Current tax on EPL (131,389) \u2013 Prior year adjustments on acquired entities (3,165) \u2013 Unrecognised tax losses (19,743) (342) Total tax charge recorded in the consolidated statement of profit or loss (1,208,997) (337,150) The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in 2022, prior to the introduction of the EPL, was 40% (2021: 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. 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\u202fchanges 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: 2022 US$\u2019000 2021 US$\u2019000 Deferred corporation tax liability (2,258,813) (688,140) Deferred corporation tax asset 2,629,548 876,904 Deferred PRT asset 21,721 32,154 Net deferred tax asset 392,456 220,918 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. Non-oil and gas losses of $156 million, of which there is no expiry date, has not been recognised for deferred tax purposes as it is not certain that there will be future non-oil and gas profits to offset these losses. The net movement on the deferred tax account is as follows: 2022 US$\u2019000 2021 US$\u2019000 At 1 January 220,918 382,114 Profit or loss (charge) (1,024,889) (355,828) Other comprehensive income (charge)/credit (200,455) 194,632 Business combinations (note 17) 1,396,882 \u2013 At 31 December 392,456 220,918 The net movement on the deferred tax account through the consolidated statement of profit or loss relates to the following: 2022 US$\u2019000 2021 US$\u2019000 Accelerated capital allowances (490,246) (149,117) Tax losses (386,819) (218,174) Abandonment provision (124,598) 24,214 Petroleum revenue tax \u2013 (12,861) Deferred PRT 4,173 \u2013 Hedging (226,040) 152,015 Investment allowances 8,617 10,573 (1,214,913) (193,350) Gross deferred corporation tax liabilities Hedges US$000 Deferred corporation tax on deferred PRT US$000 Accelerated tax depreciation US$000 Total US$000 At 1 January 2021 26,941 \u2013 (536,735) (509,794) Reclass to deferred corporation tax assets (26,941) \u2013 \u2013 (26,941) Prior year adjustment \u2013 \u2013 (15,813) (15,813) Origination and reversal of temporary differences \u2013 (12,861) (122,731) (135,592) At 31 December 2021 \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) (647,743) Origination and reversal of temporary differences \u2013 4,173 (485,985) (481,812) At 31 December 2022 \u2013 (8,688) (2,250,125) (2,258,813) Gross deferred corporation tax assets Abandonment provision US$000 Tax losses US$000 Hedges US$000 Total US$000 At 1 January 2021 173,452 718,456 \u2013 891,908 Reclass from deferred corporation tax liabilities \u2013 \u2013 26,941 26,941 Prior year adjustment \u2013 14,599 \u2013 14,599 Origination and reversal of temporary differences 24,214 (232,773) 152,015 (56,544) At 31 December 2021 197,666 500,282 178,956 876,904 Prior year adjustment \u2013 3,706 \u2013 3,706 Reclassification of decommissioning asset 436,772 \u2013 \u2013 436,772 Business combinations 156,212 1,858,706 38,406 2,053,324 Origination and reversal of temporary differences (124,598) (390,520) (226,040) (741,158) At 31 December 2022 666,052 1,972,174 (8,678) 2,629,548 Deferred PRT asset Total $000 At 1 January 2021 \u2013 Profit or loss credit 32,154 At 31 December 2021 32,154 Origination and reversal of temporary differences (10,433) At 31 December 2022 21,721 The carrying value of the net deferred corporation tax asset at 31 December 2022 of $371 million (2021: $189 million) is 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 are undertaking a restructuring exercise which will result in certain assets being moved between Group entities. The recoverability of the deferred corporation tax asset is supported by this restructuring and a well-developed plan is in place to implement these changes. The DTA relating to losses within the Group are expected to unwind against taxable profits before the end of 2027. The Energy Profits Levy (EPL) was enacted on 14th 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 17th November 2022, the EPL was increased to 35% and extended to 31 March 2028 regardless of 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. The impact of the EPL is to increase the deferred tax liability by $780 million thereby reducing the overall deferred tax\u202fasset of the Group by $780 million. 28. Commitments and contingencies 2022 US$\u2019000 2021 US$\u2019000 Capital commitments Capital commitments incurred jointly with other venturers (Group\u2019s share) 52,309 83,368 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 2022, the Group had commitments for future capital expenditure amounting to $52.3 million. The key components of this relate to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction, platform abandonment on Anglia and drilling at the Shaw field. As of 31 December 2021, the Group had commitments for future capital expenditure amounting to $83.4 million. The key components of this relate to the Captain enhanced oil recovery programme, investments on the Abigail field and upgrade works planned on Jade and Pierce. 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 2021 and 2022, the Group had \u00a3341 million and \u00a3383 million, respectively, in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements. 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. 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 2022 are set out below: Measured at amortised cost $\u2019000 Mandatorily measured at fair value through profit or loss $\u2019000 Derivatives designated in hedge relationships $\u2019000 Total carrying amount $\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 (67,904) (258,896) \u2013 (326,800) Derivative financial instruments \u2013 (57,546) (106,563) (164,109) (1,596,093) The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2021 are set out below: Measured at amortised cost $\u2019000 Mandatorily measured at fair value through profit or loss $\u2019000 Derivatives designated in hedge relationships $\u2019000 Total carrying amount $\u2019000 Financial assets Cash and cash equivalents 44,849 \u2013 \u2013 44,849 Trade and other receivables 228,290 \u2013 \u2013 228,290 Derivative financial instruments \u2013 \u2013 5,108 5,108 Financial liabilities Borrowings (1,391,692) \u2013 \u2013 (1,391,692) Trade and other payables (427,726) \u2013 \u2013 (427,726) Lease liability (3,489) \u2013 \u2013 (3,489) Contingent and deferred consideration (19,480) (55,610) \u2013 (75,090) Derivative financial instruments \u2013 (2,009) (457,293) (459,302) (2,079,052) The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as of 31 December 2022: Level 1 US$\u2019000 Level 2 US$\u2019000 Level 3 US$\u2019000 Total Fair Value US$\u2019000 Contingent consideration (note 25) \u2013 (35,650) (223,246) (258,896 Derivative financial instrument asset \u2013 172,049 \u2013 172,049 Derivative financial instrument liability \u2013 (164,109) \u2013 (164,109) Movement in level 3 financial instruments in the 12 months to 31 December 2022 is as follows: US$\u2019000 At 1 January 2022 (19,480) Business combinations (210,096) Reversal 1,100 Accretion (5,208) Changes in fair value 10,438 At 31 December 2022 (223,246) The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as of 31 December 2021: Level 1 US$\u2019000 Level 2 US$\u2019000 Level 3 US$\u2019000 Total Fair Value US$\u2019000 Contingent consideration (note 25) \u2013 \u2013 (19,480) (19,480) Derivative financial instrument asset \u2013 5,108 \u2013 5,108 Derivative financial instrument liability \u2013 (459,302) \u2013 (459,302) Movement in level 3 financial instruments in the 12 months to 31 December 2021 is as follows: US$\u2019000 At 1 January 2021 (14,200) Additions (13,530) Changes in fair value 8,250 At 31 December 2022 (19,480) The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of profit or loss: 2022 US$\u2019000 2021 US$\u2019000 Revaluation of forex forward contracts (28,172) (8,261) Revaluation of commodity hedges 44,959 \u2013 16,787 (8,261) Realised (loss)/gain on commodity hedges (16,215) 7,808 Total gain/(loss) on financial instruments 572 (453) Hedging reserve The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of comprehensive income: Hedging reserve 2022 US$\u2019000 2021 US$\u2019000 Revaluation gain/(loss) of derivative contracts 492,900 (371,213) Realised loss on derivative contracts (582,445) (360,629) Amounts recycled to revenue 501,513 196,181 Amounts recycled to revenue \u2013 oil put premiums 14,629 27,179 Amounts recycled to revenue \u2013 gas put premiums 42,347 14,627 Amounts recycled to finance costs \u2013 interest put premiums (851) 7,276 Total gain/(loss) 468,093 (486,579) 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 purchases. Because the critical terms (i.e. the quantity, maturity and underlying) 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 2022 year end: Derivative Term Volume Average price Oil puts n/a \u2013 bbls n/a 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 below represents total commodity hedges in place at the 2021 year end: Derivative Term Volume Average price Oil puts Jan 22 \u2013 Dec 22 2,080,500 bbls $64/bbl Oil swaps Jan 22 \u2013 Dec 23 4,851,984 bbls $56/bbl Oil collars Jan 22 \u2013 Dec 23 3,558,750 bbls $58/bbl floor \u2013 $80/bbl ceiling Gas swaps Jan 22 \u2013 Dec 22 203,900,000 therms 64p/therm Gas puts Jan 22 \u2013 Dec 23 36,500,000 therms 40p/therm Gas collars Jan 22 \u2013 Dec 23 73,000,000 therms 60p/therm floor \u2013 94p/therm ceiling The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in realised commodity price 2022 US$\u2019000 2021 US$\u2019000 20% decrease in realised oil price (246,914) (271,610) 20% decrease in realised gas price (330,285) (144,905) 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 Facilities 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. Management have considered the impact of the IBOR reform on historic interest rate swaps and do not consider this to present significant additional risk to the Group and as such, have started a process to agree a transition with the interest rate swap counterparties to reduce any future impact on the financial statements after the 2023 transition date. 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 below represents interest rate financial instruments in place at the 2021 year end: Derivative Term Value Rate Interest rate swap (floating to fixed) Jan 21 \u2013 Dec 23 $50 million 0.22% The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. Change in interest rate 2022 US$\u2019000 2021 US$\u2019000 Increase of 250 basis points (11,126) (15,377) 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-USD amounts and on balance sheet translation of monetary accounts denominated in non-USD amounts upon spot rate fluctuations from quarter to quarter. 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 2021 the Group had an average of \u00a316 million per quarter hedged at an average forward rate of $1.375:\u00a31 for the period January to December 2022. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is not material. Change in GBP foreign exchange rate 2022 US$\u2019000 2021 US$\u2019000 10% weakening of GBP against USD (139,633) (33,915) A 10% strengthening of GBP against USD 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 Group\u2019s accounts receivable 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, Abigail and the MonArb fields is sold to ENI, Columba is sold to Repsol, Mariner to Equinor ASA, Schiehallion and Pierce to Shell International Trading, and Captain, Alba, Cook and Forties fields to BP Oil International. Forties fields, Stella, Vorlich, Jade and Abigail gas is sold to BP Gas Marketing. The agreement to sell Vorlich gas to Gazprom was terminated with effect from 30 September 2022 and production from these fields has subsequently been sold to BP Gas Marketing. Cook gas is sold to Shell International Trading and Esso Exploration, Schiehallion to EnQuest, and gas production from the MonArb fields is sold to Axpo Solutions AG. 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 2022, 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 2022 (31 December 2021: $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 2022, the Group\u2019s exposure is $nil (31 December 2021: $5.0 million). Judgements made in relation to the recognition of CVA/DVA can be found in note 3. The Group also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values. v) Liquidity risk Liquidity risk includes the risk that as a result of its operational liquidity requirements the Group will not have sufficient funds to settle a transaction on the due date. The Group manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Group considers the maturity profiles of its financial assets and liabilities. As at 31 December 2021 and 2022 substantially all accounts payable are current. The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2022: Within 1 year US$\u2019000 Within 2 to 5 years US$\u2019000 More than 5 Years US$\u2019000 Trade and other payables (618,460) \u2013 \u2013 Derivatives (136,668) (27,440) \u2013 Contingent and deferred consideration (116,518) (279,780) \u2013 Lease liabilities (44,257) (17,439) \u2013 Borrowings (56,250) (1,382,411) \u2013 (972,153) (1,707,070) \u2013 The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2021: Within 1 year US$\u2019000 Within 2 to 5 years US$\u2019000 More than 5 years US$\u2019000 Trade and other payables (484,268) \u2013 \u2013 Derivatives (438,006) (21,296) \u2013 Contingent and deferred consideration (49,806) (25,284) \u2013 Lease liabilities (2,094) (1,617) \u2013 Borrowings (437,076) (1,025,435) \u2013 (1,411,250) (1,073,632) \u2013 vi) Capital management The Group\u2019s objectives when managing capital are to safeguard the Group\u2019s ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required. The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates eroding the Group\u2019s financial results. 30. Derivative financial instruments
2022
US$\u2019000
2021
US$\u2019000
Oil swaps \u2013 cash flow hedge (28,685) (102,704)
Oil swaps \u2013 non-cash flow hedge (15,027) \u2013
Oil collars \u2013 cash flow hedge (21,983) (6,542)
Oil puts \u2013 cash flow hedge \u2013 (9,402)
Gas swaps \u2013 cash flow hedge 19,797 (264,345)
Gas swaps \u2013 non-cash flow hedge (29,271) \u2013
Gas puts \u2013 cash flow hedge 9,746 (3,317)
Gas collars \u2013 cash flow hedge 79,489 (66,007)
Interest rate swaps \u2013 cash flow hedge \u2013 133
Interest rate swaps \u2013 non-cash flow hedge 7,125 \u2013
FX forwards \u2013 non-cash flow hedge (13,250) (2,010)
7,941 (454,194)
Maturity analysis of derivative financial instruments
2022
US$\u2019000
2021
US$\u2019000
Non-current assets 21,191 133
Current assets 150,858 4,975
Non-current liabilities (27,440) (21,296)
Current liabilities (136,668) (438,006)
7,941 (454,194)
Judgements and estimates applied in the valuation of derivative instruments can be found in note 3.
Derivative financial instruments that are with counterparties included within the RBL are subject to Master Netting Agreements.
31. Fair values of financial assets and liabilities Financial instruments of the Group consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in the financial statements. At 31 December the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows: Classification 2022 US$\u2019000 2021 US$\u2019000 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (held for trading) 253,822 253,822 44,849 44,849 Trade and other receivables 359,994 359,994 18,918 18,918 Derivative financial instruments 172,049 172,049 5,108 5,108 Deposits 9,055 9,055 10,536 10,536 Bank debt (loans and bonds) (1,213,731) (1,257,885) (329,616) (312,741) Trade and other payables (618,460) (618,460) (13,901) (13,901) Contingent and deferred consideration (326,800) (326,800) (75,090) (75,090) Derivative financial instruments (164,109) (164,109) (459,302) (459,302) Lease liabilities (58,858) (58,858) (3,489) (3,489) 32. Related party transactions The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) who owns 89.24% 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 Yitzhak (Sharon) Tshuva. The consolidated financial statements include the financial information of the Group and the subsidiaries listed in the following table: Registered office Country of incorporation % equity interest at 31 December 2022 2021 Ithaca Energy (E&P) Limited (formerly Ithaca Energy Inc.) 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 (formerly Chevron North Sea 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 SPL Limited*** 4 England and Wales \u2013 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% \u2013 Ithaca SP Bonds PLC (formerly Siccar Point Energy Bonds PLC)** 4 England and Wales 100% \u2013 Ithaca SP Finance Limited (formerly Siccar Point Energy Finance Limited)** 4 England and Wales 100% \u2013 Ithaca SP (Holdings) Limited (formerly Siccar Point Energy (Holdings) Limited)** 4 England and Wales 100% \u2013 Registered office Country of incorporation
% equity interest at 31 December
2022 2021
Ithaca SP (E&P) Limited (formerly Siccar Point Energy E&P Limited)** 4 England and Wales 100% \u2013
Ithaca SP (O&G) Limited (formerly Siccar Point Energy UK Limited)** 4 England and Wales 100% \u2013
Ithaca SPE Limited (formerly Siccar Point Energy Limited)** 4 England and Wales 100% \u2013
Ithaca Zeta Limited (formerly Summit Exploration and Production Limited)** 4 England and Wales 100% \u2013
Transactions between subsidiaries are eliminated on consolidation.
* The Group acquired 100% of the share capital of Ithaca MA Limited (formerly Marubeni Oil & Gas (UK) Limited) on 4 February 2022. Further details on the acquisition are set out in note 17.
** The Group acquired 100% of the share capital of Ithaca SP Bonds PLC, Ithaca SP Finance Limited, Ithaca SP (Holdings Limited), Ithaca SP (E&P) Limited, Ithaca SP (O&G) Limited, Ithaca SP UK Limited, Ithaca SPE Limited and Ithaca Zeta Limited on 30 June 2022. Further details on the acquisitions are
set out in note 17.
*** Ithaca SPL Limited was dissolved on 15 February 2022.
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
The following table provides the loan balances with related parties as of 31 December:
Borrowings \u2013 principal amount (note 20)
2022
US$\u2019000
2021
US$\u2019000
Subordinated loan due to DKL Energy Limited \u2013 (63,000)
Capital Notes issued to DKL Energy Limited \u2013 (374,076)
\u2013 (437,076)
Amounts due to parent (note 22)
2022
US$\u2019000
2021
US$\u2019000
Delek Group Limited \u2013 (28,941)
Subordinated loan due to DKL Energy Limited \u2013 (14,090)
Other amounts owed to parent \u2013 (377)
\u2013 (43,408)
The outstanding interest of $29 million with respect to the 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 (note 20) and subsequent settlement of the $392 million balance
under the waiver agreement as detailed below.
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 the Capital Note and subordinated Loan balances (including interest)
totalling $469 million, such that, post IPO these balances would no longer be due from Ithaca Energy plc.
The following table provides breakdown of amounts settled under the waiver agreement: Status of outstanding loans as of 8 November 2022 Outstanding Balance US$\u2019000 Repayment of loans US$\u2019000 Loan Waiver US$\u2019000 Subordinated loan due to DKL Energy Limited (63,000) 63,000 \u2013 Subordinated loan due to DKL Energy Limited (interest) (14,406) 14,406 \u2013 Capital Notes issued to DKL Energy Limited (392,000) 210,055 (181,945) (469,406) 287,461 (181,945) The loan waiver of $181.9 million was recognised as a Capital Contribution on equity. The following table provides remuneration to key management personnel, being persons having direct or indirect authority or responsibility of the Group, for the periods ended 31 December 2022 and 2021: Key management personnel 2022 US$\u2019000 2021 US$\u2019000 Salaries and short-term employee benefits 4,590 3,136 Payments made in lieu of pension contributions 229 112 Company pension contributions 106 155 Share-based payment 12,623 \u2013 17,548 3,403 Further detail regarding share-based payments received by key management personnel is set out below. 33. Share-based payments The charge for share-based payment transactions in the year to 31 December 2022 was $14.1 million (2021: $nil). 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, pre-licence exploration costs or general and administrative costs. 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 9,433,494 Balance at 31 December 2022 1,687,296 4,908,903 2,836,660 9,433,494 Exercisable at 31 December 2022 \u2013 \u2013 \u2013 \u2013 Exercise price $nil $nil $nil N/A Weighted average remaining life 0.9 years 2.9 years 3.3 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 vest over the period to 14 November 2023, the At-IPO awards vest over the period to 14 November 2025 and the 2022 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 2022 was $0.6 million (2021: $nil). IPO-related share options Under the terms section 11.6 of the Prospectus, the Executive Chairman, Gilad Myerson (GM) and the 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 vest equally over the period 21 July 2021 to 20 July 2026. During the year Mr Myerson exercised 1,402,759 share options. The total charge for\u202fIPO-related share options in the year to 31 December 2022 was $7.3 million (2021: $nil). GM options AB options Total Balance at 1 January 2022 \u2013 \u2013 \u2013 Granted during the year 2,337,931 2,337,931 4,675,862 Exercised during the year (1,402,759) \u2013 (1,402,759) Balance at 31 December 2022 935,172 2,337,931 3,273,103 Exercisable at 31 December 2022 935,172 467,586 1,612,852 Exercise price \u00a30.01 \u00a30.01 N/A Weighted average remaining life N/A 2.7 years N/A Management Equity Plan (MEP) During the year 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) described below. These options have the following vesting conditions: Period Percentage vesting B1 B2 to 1 October 2022 0% 0% 1 October 2022 to 30 September 2023 15% 0% 1 October 2023 to 30 September 2024 30% 0% 1 October 2024 to 30 September 2025 45% 45% 1 October 2025 to 30 September 2026 100% 100% Under the terms of the MIA there is a reassessment of the overall value of Ithaca Energy plc at each vesting date and under certain circumstances Mr Myerson could be awarded further B1 and B2 shares which would vest as above. If an exit event (for example a takeover of the Group) occurs on or after 1 October 2024 then the B1 and B2 shares would immediately vest in full. Should Mr Myerson become a bad leaver before the end of the vesting period his entitlement to the shares would be as at the termination date and there would be no further vesting. Under the terms of the SSBA, Mr Myerson is also entitled to an AGP of $10.0 million, less any special bonuses paid since September 2021, if no exit is completed before 1 October 2023. The payment is in lieu of all MEP shares which must be transferred back to the Company for nil payment. The payment is intended to operate as a floor on the value that Mr Myerson may receive in recognition of his contribution to value creation from 2019 onwards and the incentive arrangements forfeited by him on commencement of employment with the Group. Entitlement to the AGP accrues evenly over the period 1 September 2021 to 30 September 2023 and is payable 1 December 2023. There are 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 2022 was $6.2 million (2021: $nil). As it is anticipated that this will be cash-settled within 12 months of the balance sheet date, this element has been treated as a current liability at 31 December 2022 and is included within accruals. The share-based payment reserve of $4.9 million reflects the charge of $0.6 million for LTIPs plus the charge of $7.3 million for IPO-related share options less the cost of exercises during the year of $3.0 million. 34. Subsequent events 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 Ithaca will receive approximately $51 million which will be reflected in the 2023 financial statements, with no amounts having been previously recognised in the financial statements. An interim dividend of $133 million, or $0.1321 per share was declared after the end of the year and was paid to shareholders on 9 March 2023.",
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"value": "2. Basis of preparation The consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standards and in conformity with the requirements of the Companies Act 2006. The consolidated financial statements are presented in US dollars as this is the functional currency of the business. All values are rounded to the nearest thousand (US$\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. ",
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"value": "3. Significant 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 IFRS) to fair value, including derivative instruments. Historical cost is generally based on the fair value consideration given in exchange for the assets. 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 Strong commodity markets in 2022, continuing robust commodity price backdrop despite lower prices during March 2023 and a well hedged portfolio over the next 12 months; \u2022 Reserves Based Lending (RBL) liquidity headroom of $475 million ($450 million drawn versus $925 million available), plus $210 million of cash as at 24 March 2023; and \u2022 Strong operational performance and well-diversified portfolio which has been further strengthened by the acquisitions of Siccar Point Energy and Summit as at 30 June 2022 and with Abigail coming online in October 2022. Cash flow forecast \u2013 base case assumptions: 2023 H1 2024 Average oil price $/bbl 77 72 Average gas price p/th 119 130 Average hedged oil price (including floor price for zero cost collars) $/bbl 69 77 Average hedged gas price (including floor price for zero cost collars) p/th 220 162 Owing to the on-going 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 there was no reasonably possible scenario that would result in the business being unable to meet its liabilities as they fell due. The Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 June 2024 to continue trading. In addition, reverse stress tests have been performed reflecting further reductions in commodity prices and production volumes, prior to any mitigating actions, to determine at what levels each would have to reach such that either lending covenants are breached or there is no liquidity headroom left. This stress test demonstrated that the likelihood of the fall in prices and production volumes required to cause a breach of covenants or liquidity issue, is considered sufficiently remote in the context of the mitigation strategies available to management. Mitigation strategies within the control of management include the reduction in uncommitted capital expenditure, variable opex savings in the low production scenario, the cancellation or deferral of future dividends and further potential to refinance the Group\u2019s borrowing arrangements. Based on their assessment of the Group\u2019s financial position in the period to 30 June 2024, 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 32. All intergroup transactions and balances have been eliminated on consolidation. Subsidiaries are all entities, including structured 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 future. 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, on a net equity basis, 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 our 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 we cannot reduce Scope 1 and Scope 2 emissions, we will invest in carbon offsets to achieve our 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 our 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 \u201ckey sources of estimation uncertainty\u201d 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 $83/bbl for Brent Crude and 86p/therm for UK NBP gas. The other areas of estimation uncertainty in this note and note 19 includes the impact on impairment headroom of a 20% downside in net revenues. Management has concluded that this reduction is also reflective of amending its long-term commodity price assumptions to those that are in line with a range of transition paths consistent with the temperature goal of the Paris climate change agreement, of holding the increase in the global average temperate at well below 2 degrees above pre-industrial levels and pursing efforts to limit the temperature to 1.5 degrees above pre-industrial levels. This assessment is based on climate change scenarios currently available from the International Energy Agency and World Business Council for Sustainable Development. Recoverable values used for impairment testing for all cash generating units (\u2018CGU\u2019s) include the estimated cost of UK carbon emissions allowances. 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 our 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 39, 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 2022, however no significant write-offs were identified. 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 twenty 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 2 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 $74 million. The risk in this area may increase if key assets within the group\u2019s existing exploration and appraisal assets proceed to development, as this is likely to significantly extend the life of the group\u2019s portfolio, in some cases to 2050 or beyond. On the basis that all other assumptions in the calculation remain the same, a 1.0% reduction in the applied discount rates used to assess the balance sheet decommissioning liability would result in an increase to the decommissioning provision of approximately $218 million (2021: $202 million). This change would be principally offset by a change in the value of the associated asset unless the asset in question is fully depreciated whereby the change in estimate would be recognised immediately through the statement of profit or loss. 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 cash generating unit (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 measured at the fair value of the consideration received or receivable and represents amounts receivable for products in the normal course of business, net of discounts, customs duties and sales taxes. 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 information 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 United States Dollars, which is the Group\u2019s presentation currency as well as the functional currency of the parent company and each of its subsidiaries. In preparing the financial statements of the parent and its subsidiaries, transactions in currencies other than the entity\u2019s functional currency (foreign currencies) are recognised at the rates of exchange prevailing on the dates of the transactions. At each reporting date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of profit or loss. Exchange differences are recognised in profit or loss in the period in which they arise except for: \u2022 Exchange differences on foreign currency borrowings relating to assets under construction for future productive use, which are included in the cost of those assets when they are regarded as an adjustment to interest costs on those foreign currency borrowings; \u2022 Exchange differences on transactions entered into to hedge certain foreign currency risks (see below under financial instruments/hedge accounting). Financial instruments All financial instruments are initially recognised at fair value on the statement of financial position. The Group\u2019s financial instruments consist of cash and cash equivalents, accounts receivable, deposits, accrued income, derivatives, accounts payable, accrued liabilities, borrowings and contingent consideration. Under IFRS 9, with the exception of derivatives and contingent considerations, all financial instruments are recorded at amortised cost based on an analysis of the business model and terms of financial assets. All financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. 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 liability derecognised and the consideration paid and payable 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 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. Although the Group does not intend to trade its derivative financial instruments, they are required to be carried at fair value with the treatment of fair value movements explained further below. Transaction costs 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. 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 is recognised in profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship. 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, which is when the hedging relationships meet all of the following hedge effectiveness requirements: \u2022 There is an economic relationship between the hedged item and the hedging instrument; \u2022 The effect of credit risk does not dominate the value changes that result from that economic relationship; and \u2022 The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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. Note 30 and 31 set out details of the fair values of the derivative instruments used for hedging purposes. Movements in the hedging reserve in equity are detailed in note 29. Cash flow hedges 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 th e 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. 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. Trade and other receivables Trade receivables are recognised and carried at the original invoiced amount, less any provision for estimated irrecoverable amounts. 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. 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. 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 accrued income or \u2018overlift\u2019, included within deferred income 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. Other receivables are carried at amortised cost using the effective interest method if the time value of money is significant. Gains and losses are recognised in the consolidated statement of profit or loss when the assets are derecognised, modified or impaired. The Group\u2019s financial assets measured at amortised cost includes trade and other receivables and amounts due from related parties. Trade and other payables All other financial liabilities are initially recognised at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing. After initial recognition, other financial liabilities are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised in interest and other income and finance costs respectively. This category of financial liabilities included trade and other payables and finance debt. Property, plant and equipment Oil and gas expenditure \u2013 exploration and evaluation (E&E) assets Geological and geophysical exploration costs are recognised as an expense 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 continued 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 internal 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. 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 Developing & Producing (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. Impairment For impairment review purposes the Group\u2019s oil and gas assets are aggregated into cash-generating units (CGUs) in accordance with IAS 36. A review is carried out 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. 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 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. 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 year s Computer and office equipment 3 years Furniture and fittings 5 years Borrowings All interest-bearing loans and other borrowings with banks are initially recognised at fair value net of directly attributable transaction costs. After initial recognition, interest-bearing loans and other borrowings are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium. 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. Loan origination fees are capitalised and amortised over the term of the loan. 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. Senior notes are measured at amortised cost. 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 & 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. 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. Settlement of contingent and deferred considerations are recorded as investing outflows in the cash flow statement. Deferred consideration is measured at amortised cost. 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. The Group recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. 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 and other long-term employee benefits A liability is recognised for benefits accruing to employees in respect of wages and salaries, 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. 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. Liabilities recognised in respect of other long-term benefits are measured at the present value of the estimated future cash outflows expected to be made by the Group in respect of services provided by employees up to the reporting date. Changes in accounting pronouncements The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2021 to 31 December 2022. 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 new and revised IFRS Standards that have been issued but are not yet effective. IFRS 17 Insurance Contracts Amendments to IAS 1 Classification of Liabilities as Current or Non-current Amendments to IAS 1 and IFRS Practice Statement 2 Disclosure of Accounting Policies Amendments to IAS 8 Definition of Accounting Estimates Amendments to IAS 12 Deferred Tax related to Assets and Liabilities arising from a Single Transaction Amendments to IFRS 16 Lease Liability in a Sale and Leaseback Amendments to IAS 1 Non-current Liabilities and Covenants The Company does not expect that the adoption of the Standards and 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 The following are the critical judgements, apart from those involving estimations (which are presented separately below), that the directors have made in the process of applying the Group\u2019s accounting policies and that have the most significant effect on the amounts recognised in financial statements. 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. 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. Although decommissioning costs are expected to be incurred over the next 40 years it is anticipated that approximately 33% of the liability will be paid within the next five years. A nominal discount rate of 4.25% (2021: 2.5%) is used to discount the estimated costs. The inflation rate applied to discount the estimated costs is 2.0% (2021: 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 variation in this discount rate of 1% would change the decommissioning liabilities by approximately $218 million (2021: $202 million), 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. Commodity derivatives 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 $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 2022 of $188 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: 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 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. 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, 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, 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 (see critical accounting judgement below). 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 2022, 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 $24 million. 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 $24 million de-recognition 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. 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. The sensitivity of the elements of contingent consideration linked to the oil price is disclosed in note 25. It is not practical to provide sensitivities to other specific assumptions given the multiple contingent events and assumptions\u202finvolved. Critical accounting judgements Acquisitions In the periods presented, the Group has made a number of acquisitions \u2013 see note 17 for further details of the final/provisional purchase price allocation, including the assets and liabilities acquired, the goodwill/gain on bargain purchase arising on acquisition and details of the contingent consideration payable. The acquisitions were accounted for as business combinations under IFRS 3. The assets and liabilities identified in the purchase price allocation include oil & gas assets, decommissioning liabilities, deferred tax assets and liabilities, derivatives and working capital. The total consideration payable includes both amounts paid at completion of each of the acquisitions and further amounts which are contingent on certain events taking place. Judgements are required to be made regarding the future value of associated contingent consideration, as further described above. The calculation of the fair value of the oil and gas assets acquired requires the Group to estimate the future cash flows expected to arise from the CGUs in the acquired business using discounted cash flow models. Key assumptions and estimates include: commodity prices, discount rates and oil and gas reserves estimates. See above estimates in the impairment of oil and gas assets and goodwill sections and estimate in the oil and gas reserves section for further details regarding these assumptions. In addition, the Group has considered the value that a market participant would prescribe to prospective resources in determining both the fair value of the oil & gas assets acquired and the contingent consideration recognised. In determining the value of the deferred tax asset recognised on acquisition, the Group has made assumptions in respect of the amount of tax losses brought forward which will be available to offset against future taxable profits of the Group. Specifically, in respect of the MOGL acquisition, assumptions have been made with regards to the group relief claims the seller is entitled to make relating to pre-completion periods (pre 4 February 2022) which would reduce the losses available to the Group, and the quantum of such claims. The provisional deferred tax asset recognised by the Group assumes full utilisation of the losses held in MOGL and therefore a change in this assumption could result in a change in the deferred tax asset recognised on the balance sheet on acquisition, which would be recognised through profit and loss in the period of this change. Further, in assessing the value of the deferred tax asset recognised in the MOGL and Siccar Point Energy acquisitions, the Group has made assumptions regarding future restructuring within the Group, therefore a change in these assumptions could result in a change in the deferred tax asset recognised. Fair value of derivative instruments 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. ",
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"fact-334": {
"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 IFRS) to fair value, including derivative instruments. Historical cost is generally based on the fair value consideration given in exchange for the assets. ",
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"fact-335": {
"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 Strong commodity markets in 2022, continuing robust commodity price backdrop despite lower prices during March 2023 and a well hedged portfolio over the next 12 months; \u2022 Reserves Based Lending (RBL) liquidity headroom of $475 million ($450 million drawn versus $925 million available), plus $210 million of cash as at 24 March 2023; and \u2022 Strong operational performance and well-diversified portfolio which has been further strengthened by the acquisitions of Siccar Point Energy and Summit as at 30 June 2022 and with Abigail coming online in October 2022. Cash flow forecast \u2013 base case assumptions: 2023 H1 2024 Average oil price $/bbl 77 72 Average gas price p/th 119 130 Average hedged oil price (including floor price for zero cost collars) $/bbl 69 77 Average hedged gas price (including floor price for zero cost collars) p/th 220 162 Owing to the on-going 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 there was no reasonably possible scenario that would result in the business being unable to meet its liabilities as they fell due. The Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 June 2024 to continue trading. In addition, reverse stress tests have been performed reflecting further reductions in commodity prices and production volumes, prior to any mitigating actions, to determine at what levels each would have to reach such that either lending covenants are breached or there is no liquidity headroom left. This stress test demonstrated that the likelihood of the fall in prices and production volumes required to cause a breach of covenants or liquidity issue, is considered sufficiently remote in the context of the mitigation strategies available to management. Mitigation strategies within the control of management include the reduction in uncommitted capital expenditure, variable opex savings in the low production scenario, the cancellation or deferral of future dividends and further potential to refinance the Group\u2019s borrowing arrangements. Based on their assessment of the Group\u2019s financial position in the period to 30 June 2024, 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. ",
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"fact-337": {
"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 32. All intergroup transactions and balances have been eliminated on consolidation. Subsidiaries are all entities, including structured 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. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-336": {
"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 future. 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, on a net equity basis, 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 our 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 we cannot reduce Scope 1 and Scope 2 emissions, we will invest in carbon offsets to achieve our 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 our 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 \u201ckey sources of estimation uncertainty\u201d 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 $83/bbl for Brent Crude and 86p/therm for UK NBP gas. The other areas of estimation uncertainty in this note and note 19 includes the impact on impairment headroom of a 20% downside in net revenues. Management has concluded that this reduction is also reflective of amending its long-term commodity price assumptions to those that are in line with a range of transition paths consistent with the temperature goal of the Paris climate change agreement, of holding the increase in the global average temperate at well below 2 degrees above pre-industrial levels and pursing efforts to limit the temperature to 1.5 degrees above pre-industrial levels. This assessment is based on climate change scenarios currently available from the International Energy Agency and World Business Council for Sustainable Development. Recoverable values used for impairment testing for all cash generating units (\u2018CGU\u2019s) include the estimated cost of UK carbon emissions allowances. 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 our 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 39, 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 2022, however no significant write-offs were identified. 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 twenty 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 2 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 $74 million. The risk in this area may increase if key assets within the group\u2019s existing exploration and appraisal assets proceed to development, as this is likely to significantly extend the life of the group\u2019s portfolio, in some cases to 2050 or beyond. On the basis that all other assumptions in the calculation remain the same, a 1.0% reduction in the applied discount rates used to assess the balance sheet decommissioning liability would result in an increase to the decommissioning provision of approximately $218 million (2021: $202 million). This change would be principally offset by a change in the value of the associated asset unless the asset in question is fully depreciated whereby the change in estimate would be recognised immediately through the statement of profit or loss. 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. ",
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"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 cash generating unit (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. ",
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"fact-394": {
"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. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-395": {
"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 cash generating unit (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. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-396": {
"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). ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-339": {
"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). ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-409": {
"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). ",
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"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-340": {
"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 measured at the fair value of the consideration received or receivable and represents amounts receivable for products in the normal course of business, net of discounts, customs duties and sales taxes. 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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},
"fact-343": {
"value": "Foreign currency translation Items included in these consolidated financial statements information 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 United States Dollars, which is the Group\u2019s presentation currency as well as the functional currency of the parent company and each of its subsidiaries. In preparing the financial statements of the parent and its subsidiaries, transactions in currencies other than the entity\u2019s functional currency (foreign currencies) are recognised at the rates of exchange prevailing on the dates of the transactions. At each reporting date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of profit or loss. Exchange differences are recognised in profit or loss in the period in which they arise except for: \u2022 Exchange differences on foreign currency borrowings relating to assets under construction for future productive use, which are included in the cost of those assets when they are regarded as an adjustment to interest costs on those foreign currency borrowings; \u2022 Exchange differences on transactions entered into to hedge certain foreign currency risks (see below under financial instruments/hedge accounting). ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForForeignCurrencyTranslationExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-341": {
"value": "Financial instruments All financial instruments are initially recognised at fair value on the statement of financial position. The Group\u2019s financial instruments consist of cash and cash equivalents, accounts receivable, deposits, accrued income, derivatives, accounts payable, accrued liabilities, borrowings and contingent consideration. Under IFRS 9, with the exception of derivatives and contingent considerations, all financial instruments are recorded at amortised cost based on an analysis of the business model and terms of financial assets. All financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. 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 liability derecognised and the consideration paid and payable 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 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. Although the Group does not intend to trade its derivative financial instruments, they are required to be carried at fair value with the treatment of fair value movements explained further below. Transaction costs 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-397": {
"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 is recognised in profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship. 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, which is when the hedging relationships meet all of the following hedge effectiveness requirements: \u2022 There is an economic relationship between the hedged item and the hedging instrument; \u2022 The effect of credit risk does not dominate the value changes that result from that economic relationship; and \u2022 The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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. Note 30 and 31 set out details of the fair values of the derivative instruments used for hedging purposes. Movements in the hedging reserve in equity are detailed in note 29. Cash flow hedges 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 th 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsAndHedgingExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-342": {
"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 is recognised in profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship. 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, which is when the hedging relationships meet all of the following hedge effectiveness requirements: \u2022 There is an economic relationship between the hedged item and the hedging instrument; \u2022 The effect of credit risk does not dominate the value changes that result from that economic relationship; and \u2022 The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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. Note 30 and 31 set out details of the fair values of the derivative instruments used for hedging purposes. Movements in the hedging reserve in equity are detailed in note 29. Cash flow hedges 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 th e 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForDerivativeFinancialInstrumentsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-410": {
"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, which is when the hedging relationships meet all of the following hedge effectiveness requirements: \u2022 There is an economic relationship between the hedged item and the hedging instrument; \u2022 The effect of credit risk does not dominate the value changes that result from that economic relationship; and \u2022 The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the 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. Note 30 and 31 set out details of the fair values of the derivative instruments used for hedging purposes. Movements in the hedging reserve in equity are detailed in note 29. Cash flow hedges 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 th e 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForHedgingExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-347": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-344": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-345": {
"value": "Trade and other receivables Trade receivables are recognised and carried at the original invoiced amount, less any provision for estimated irrecoverable amounts. 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. 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. 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 accrued income or \u2018overlift\u2019, included within deferred income 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. Other receivables are carried at amortised cost using the effective interest method if the time value of money is significant. Gains and losses are recognised in the consolidated statement of profit or loss when the assets are derecognised, modified or impaired. The Group\u2019s financial assets measured at amortised cost includes trade and other receivables and amounts due from related parties. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-346": {
"value": "Trade and other payables All other financial liabilities are initially recognised at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing. After initial recognition, other financial liabilities are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised in interest and other income and finance costs respectively. This category of financial liabilities included trade and other payables and finance debt. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-348": {
"value": "Property, plant and equipment Oil and gas expenditure \u2013 exploration and evaluation (E&E) assets Geological and geophysical exploration costs are recognised as an expense 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 continued 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 internal 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.
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
Developing & Producing (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 year s
Computer and office equipment 3 years
Furniture and fittings 5 years
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-398": {
"value": "Oil and gas expenditure \u2013 exploration and evaluation (E&E) assets Geological and geophysical exploration costs are recognised as an expense 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 continued 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 internal 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. 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 Developing & Producing (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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForOilAndGasAssetsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-349": {
"value": "Impairment For impairment review purposes the Group\u2019s oil and gas assets are aggregated into cash-generating units (CGUs) in accordance with IAS 36. A review is carried out 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. 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 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. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-351": {
"value": "Borrowings
All interest-bearing loans and other borrowings with banks are initially recognised at fair value net of directly attributable transaction costs. After initial recognition, interest-bearing loans and other borrowings are subsequently
measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium.
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.
Loan origination fees are capitalised and amortised over the term of the loan. 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.
Senior notes are measured at amortised cost.
",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForBorrowingsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-352": {
"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 & 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-350": {
"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. Settlement of contingent and deferred considerations are recorded as investing outflows in the cash flow statement. Deferred consideration is measured at amortised cost. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForContingentLiabilitiesAndContingentAssetsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-353": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-399": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-354": {
"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. The Group recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-357": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-355": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-358": {
"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 and other long-term employee benefits A liability is recognised for benefits accruing to employees in respect of wages and salaries, 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. 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. Liabilities recognised in respect of other long-term benefits are measured at the present value of the estimated future cash outflows expected to be made by the Group in respect of services provided by employees up to the reporting date. ",
"dimensions": {
"concept": "ifrs-full:DescriptionOfAccountingPolicyForEmployeeBenefitsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-356": {
"value": "Changes in accounting pronouncements The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2021 to 31 December 2022. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfChangesInAccountingPoliciesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-359": {
"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 new and revised IFRS Standards that have been issued but are not yet effective. IFRS 17 Insurance Contracts Amendments to IAS 1 Classification of Liabilities as Current or Non-current Amendments to IAS 1 and IFRS Practice Statement 2 Disclosure of Accounting Policies Amendments to IAS 8 Definition of Accounting Estimates Amendments to IAS 12 Deferred Tax related to Assets and Liabilities arising from a Single Transaction Amendments to IFRS 16 Lease Liability in a Sale and Leaseback Amendments to IAS 1 Non-current Liabilities and Covenants The Company does not expect that the adoption of the Standards and 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-360": {
"value": "Critical judgements and key sources of estimation uncertainties The following are the critical judgements, apart from those involving estimations (which are presented separately below), that the directors have made in the process of applying the Group\u2019s accounting policies and that have the most significant effect on the amounts recognised in financial statements. 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.
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. Although decommissioning costs are expected to be incurred over the next 40 years it is anticipated that
approximately 33% of the liability will be paid within the next five years. A nominal discount rate of 4.25% (2021: 2.5%) is used to discount the estimated costs. The inflation rate applied to discount the estimated costs is 2.0% (2021:
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 variation in this discount rate of 1% would change the decommissioning liabilities by approximately $218 million (2021: $202 million), 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.
Commodity derivatives
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 $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 2022 of $188 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:
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 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. 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, 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, 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 (see critical accounting judgement below). 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 2022, 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 $24 million. 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 $24 million de-recognition 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. 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. The sensitivity of the elements of contingent consideration linked to the oil price is disclosed in note 25. It is not practical to provide sensitivities to other specific assumptions given the multiple contingent events and assumptions\u202finvolved. Critical accounting judgements
Acquisitions
In the periods presented, the Group has made a number of acquisitions \u2013 see note 17 for further details of the final/provisional purchase price allocation, including the assets and liabilities acquired, the goodwill/gain on bargain
purchase arising on acquisition and details of the contingent consideration payable. The acquisitions were accounted for as business combinations under IFRS 3. The assets and liabilities identified in the purchase price allocation
include oil & gas assets, decommissioning liabilities, deferred tax assets and liabilities, derivatives and working capital.
The total consideration payable includes both amounts paid at completion of each of the acquisitions and further amounts which are contingent on certain events taking place. Judgements are required to be made regarding the
future value of associated contingent consideration, as further described above.
The calculation of the fair value of the oil and gas assets acquired requires the Group to estimate the future cash flows expected to arise from the CGUs in the acquired business using discounted cash flow models. Key assumptions
and estimates include: commodity prices, discount rates and oil and gas reserves estimates. See above estimates in the impairment of oil and gas assets and goodwill sections and estimate in the oil and gas reserves section for
further details regarding these assumptions. In addition, the Group has considered the value that a market participant would prescribe to prospective resources in determining both the fair value of the oil & gas assets acquired and
the contingent consideration recognised.
In determining the value of the deferred tax asset recognised on acquisition, the Group has made assumptions in respect of the amount of tax losses brought forward which will be available to offset against future taxable profits of
the Group. Specifically, in respect of the MOGL acquisition, assumptions have been made with regards to the group relief claims the seller is entitled to make relating to pre-completion periods (pre 4 February 2022) which would
reduce the losses available to the Group, and the quantum of such claims. The provisional deferred tax asset recognised by the Group assumes full utilisation of the losses held in MOGL and therefore a change in this assumption
could result in a change in the deferred tax asset recognised on the balance sheet on acquisition, which would be recognised through profit and loss in the period of this change.
Further, in assessing the value of the deferred tax asset recognised in the MOGL and Siccar Point Energy acquisitions, the Group has made assumptions regarding future restructuring within the Group, therefore a change in these
assumptions could result in a change in the deferred tax asset recognised.
Fair value of derivative instruments
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.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAccountingJudgementsAndEstimatesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-363": {
"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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-361": {
"value": "5. Revenue 2022 US$\u2019000 2021 US$\u2019000 Oil sales 1,692,697 856,492 Gas sales 1,348,212 724,527 NGL sales 75,445 52,466 Other income 40,617 32,742 Realised losses on oil derivative contracts (211,636) (48,833) Put premiums on oil derivative instruments (14,629) (27,179) Realised losses on gas derivative contracts (289,877) (147,348) Put premiums on gas derivative instruments (42,347) (14,627) 2,598,482 1,428,240 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 one customer exceeds 10% of the Group\u2019s consolidated revenue arising from hydrocarbon sales for the year ended 31 December 2022 (31 December 2021: one), representing $2,436 million for the year ended 31 December 2022 (2021: $1,437 million). Revenue from contracts with customers derives largely from customers within a single geographical region, being the United Kingdom. Revenue from contracts with customers out with the United Kingdom is immaterial and is therefore not disclosed separately. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfRevenueExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-362": {
"value": "6. Cost of sales 2022 US$\u2019000 2021 US$\u2019000 Movement in oil and gas inventory (130,295) 6,970 Operating costs (547,795) (424,046) Royalties (11,287) (6,192) Depreciation on right-of-use assets (note 15) (37,438) (5,613) Depletion, depreciation and amortisation (note 15) (625,509) (450,300) (1,352,324) (879,181) Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds a 100% interest in the Stella and Harrier fields. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCostOfSalesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-364": {
"value": "7. Administrative expenses 2022 US$\u2019000 2021 US$\u2019000 General and administrative (27,693) (15,180) Share-based payment charge (note 33) (14,069) \u2013 Transaction costs (46,089) \u2013 (87,851) (15,180) Transactions costs in 2022 relate to the acquisitions of MOGL, Summit Exploration and Production Limited (Summit) and Siccar Point Energy entities, and costs incurred in connection to the IPO. Further details on the acquisitions can be found in note 17. The total employee benefit expenses which is either capitalised or included in cost of sales and administrative expenses are noted below. Employee benefit expenses 2022 US$\u2019000 2021 US$\u2019000 Wages and salaries (81,017) (62,546) Social security costs (9,902) (7,132) Pension costs (8,298) (7,505) (99,217) (77,183) The average number of employees for the year was as follows: 2022 2021 Onshore and administrative 268 251 Offshore 249 217 517 468 Audit fees 2022 US$\u2019000 2021 US$\u2019000 Fees payable to the current Company\u2019s auditor for audit of the Company\u2019s financial statements (1,095) (685) Fees payable to the previous Company\u2019s auditor for audit of the Company\u2019s financial statements \u2013 (35) Audit of the Company\u2019s subsidiaries pursuant to legislation (279) (62) Non-audit fees provided by the current auditors (4,707) \u2013 Non-audit fees provided by the previous auditors \u2013 (236) (6,081) (1,018) Non-audit fees provided by the current auditors for the year ended 31 December 2022 comprise audit-related assurance services of $170k, other assurance services of $990k and other non-audit services of $3,547k, with the latter two captions relating to reporting accountant workstreams in relation to the IPO. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGeneralAndAdministrativeExpenseExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-400": {
"value": "Audit fees 2022 US$\u2019000 2021 US$\u2019000 Fees payable to the current Company\u2019s auditor for audit of the Company\u2019s financial statements (1,095) (685) Fees payable to the previous Company\u2019s auditor for audit of the Company\u2019s financial statements \u2013 (35) Audit of the Company\u2019s subsidiaries pursuant to legislation (279) (62) Non-audit fees provided by the current auditors (4,707) \u2013 Non-audit fees provided by the previous auditors \u2013 (236) (6,081) (1,018) Non-audit fees provided by the current auditors for the year ended 31 December 2022 comprise audit-related assurance services of $170k, other assurance services of $990k and other non-audit services of $3,547k, with the latter two captions relating to reporting accountant workstreams in relation to the IPO. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfAuditorsRemunerationExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-365": {
"value": "8. Other gains and losses 2022 US$\u2019000 2021 US$\u2019000 Loss on financial instruments (278) (453) Fair value (losses)/gains on contingent consideration (4,295) 8,250 Net foreign exchange (4,856) (3,970) (9,429) 3,827 ",
"dimensions": {
"concept": "ithacaenergyplc:DisclosureOfOtherGainsAndLosses",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-366": {
"value": "9. Net finance costs 2022 US$\u2019000 2021 US$\u2019000 Bank interest and charges (58,317) (41,372) Senior notes interest (61,537) (74,677) Loan fee amortisation (6,418) (35,343) Interest on lease liabilities (note 24) (3,852) (367) Interest on related party loan (note 32) (17,924) (48,277) Accretion (56,511) (38,348) Realised gains/(losses) on interest derivative contracts (note 29) 851 (7,276) Interest income 695 11 Other \u2013 (4,487) (203,013) (250,136) There was no interest capitalised into qualifying assets in either the year to 31 December 2022 or the year to 31 December 2021. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExpenseExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-411": {
"value": "9. Net finance costs 2022 US$\u2019000 2021 US$\u2019000 Bank interest and charges (58,317) (41,372) Senior notes interest (61,537) (74,677) Loan fee amortisation (6,418) (35,343) Interest on lease liabilities (note 24) (3,852) (367) Interest on related party loan (note 32) (17,924) (48,277) Accretion (56,511) (38,348) Realised gains/(losses) on interest derivative contracts (note 29) 851 (7,276) Interest income 695 11 Other \u2013 (4,487) (203,013) (250,136) There was no interest capitalised into qualifying assets in either the year to 31 December 2022 or the year to 31 December 2021. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceCostExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-401": {
"value": "9. Net finance costs 2022 US$\u2019000 2021 US$\u2019000 Bank interest and charges (58,317) (41,372) Senior notes interest (61,537) (74,677) Loan fee amortisation (6,418) (35,343) Interest on lease liabilities (note 24) (3,852) (367) Interest on related party loan (note 32) (17,924) (48,277) Accretion (56,511) (38,348) Realised gains/(losses) on interest derivative contracts (note 29) 851 (7,276) Interest income 695 11 Other \u2013 (4,487) (203,013) (250,136) There was no interest capitalised into qualifying assets in either the year to 31 December 2022 or the year to 31 December 2021. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFinanceIncomeExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-368": {
"value": "10. Earnings per share The calculation of basic earnings per share is based on the profit after tax and the weighted average number of ordinary shares in issue during the year. Basic and diluted earnings per share are calculated as follows: 2022 US$\u2019000 2021 US$\u2019000 Earnings for the year: Earnings for the purpose of basic earnings per share 1,031,532 425,989 Effect of dilutive potential ordinary shares \u2013 \u2013 Earnings for the purpose of diluted earnings per share 1,031,532 425,989 Number of shares (million) Weighted average number of ordinary shares for the purpose of basic earnings per share 1 1,005.2 1,005.2 Dilutive potential ordinary shares 5.0 2.1 Weighted average number of ordinary shares for the purpose of diluted earnings per share 1,010.2 1,007.3 Earnings per share (cents) Basic 102.6 42.4 Diluted 102.2 42.3 1 In accordance with IAS 33 paragraph 64, following the issue of bonus shares (900,073,953) and new shares (105,000,000) in connection to the IPO, the weighted average number of shares in 2022 and 2021 have been retrospectively restated to reflect the number of shares post IPO. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEarningsPerShareExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-367": {
"value": "11. Trade and other receivables Current 2022 US$\u2019000 2021 US$\u2019000 Trade receivables 31,906 18,918 Other receivables 14,210 25,420 Joint venture receivables 99,800 79,917 Accrued income 214,078 104,035 359,994 228,290 The Group regularly monitors all customer receivable balances outstanding in excess of 90 days for expected credit losses. The Group applies a simplified approach in calculating Expected Credit Losses (ECLs) as allowed under IFRS 9. Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, the economic environment and the Group\u2019s historical credit loss experience. Substantially all trade and other receivables are current, being defined as less than 90 days and as such no ECLs have been recognised in the current or prior year as the ECL is considered immaterial. Non-current 2022 US$\u2019000 2021 US$\u2019000 Decommissioning reimbursement 162,710 152,184 Current 2022 US$\u2019000 2021 US$\u2019000 Decommissioning reimbursement 38,115 94,640 The decommissioning reimbursement represents the equal and opposite of decommissioning liabilities (note 23), net of tax, associated with the Heather and Strathspey fields and relates to a contractual agreement as part of the CNSL acquisition. As part of the terms of the CNSL acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL in relation to these interests. As the payment is virtually certain this has been accounted for under IAS 37 as a reimbursement asset. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherReceivablesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-369": {
"value": "12. Prepaid expenses and decommissioning securities Current 2022 US$\u2019000 2021 US$\u2019000 Prepayments 7,415 8,524 Decommissioning securities 1,640 2,012 9,055 10,536 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfPrepaymentsAndOtherAssetsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-371": {
"value": "13. Inventories Current 2022 US$\u2019000 2021 US$\u2019000 Hydrocarbon inventories/underlift 87,563 115,743 Materials inventories 124,755 89,374 Provision for obsolete materials inventory (35,437) (27,498) 176,881 177,619 Non-current 2022 US$\u2019000 2021 US$\u2019000 Hydrocarbon inventories \u2013 532 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfInventoriesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-370": {
"value": "14. Exploration and evaluation assets US$\u2019000 At 1 January 2021 70,589 Additions 45,922 Write offs/relinquishments (156) At 31 December 2021 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 775,773 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 $14.3 million being expensed in the year to 31 December 2022 (2021: $0.2 million). The transfers from exploration and evaluation assets to development and production assets relates to the Abigail and Jade South wells. The write offs/relinquishments includes $5.3 million of impairment relating to decommissioning revisions. The principal exploration and evaluation assets at 31 December 2022 are Cambo and Rosebank which formed part of the Siccar acquisition (see note 17). ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfExplorationAndEvaluationAssetsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-372": {
"value": "15. Property, plant and equipment Right-of-use operating assets US$\u2019000 Development and production assets US$\u2019000 Other fixed assets US$\u2019000 Total US$\u2019000 Cost At 1 January 2021 13,139 5,496,465 18,856 5,528,460 Additions 2,512 341,713 21,437 365,662 Disposals (6,441) \u2013 \u2013 (6,441) At 31 December 2021 and 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 98,927 7,112,652 45,912 7,257,491 Depletion, depreciation, amortisation and Impairment At 1 January 2021 (6,257) (2,930,215) (8,275) (2,944,747) Depletion, depreciation and amortisation charge for the year (5,613) (444,751) (5,549) (455,913) Disposals 6,441 \u2013 \u2013 6,441 Impairment reversal (note 19) \u2013 465,271 \u2013 465,271 At 31 December 2021 and 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 (42,867) (3,555,656) (24,072) (3,622,595) Net book value at 31 December 2021 3,781 2,928,483 26,469 2,958,733 Net book value at 31 December 2022 56,060 3,556,996 21,840 3,634,896 The transfers from exploration and evaluation assets to development and production assets relates to the Abigail and Jade South wells. At the point of transfer these assets were tested for impairment and none was found. Other fixed assets includes buildings, computer equipment, office equipment and furniture and fittings. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfPropertyPlantAndEquipmentExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-373": {
"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:
Block Licence Field/Discovery Name Operator
Group Net % Interest
2022 2021
9/11c P.979 Mariner Equinor UK Limited 8.89% 0.00%
9/11b P.726 Mariner Equinor UK Limited 8.89% 0.00%
30/2c P.672 Jade Chrysaor Petroleum Company UK Limited 15.50% 6.64%
22/30c and 29/5c P.666 Elgin-Franklin TotalEnergies E&P UK Limited 6.09% 1.95%
15/29b P.590 Callanish Chrysaor Production (UK) Limited 20.00% 20.00%
204/25a P.559 Schiehallion BP Exploration Operating Company Limited 35.30% 0.00%
204/19b and 204/20b P.556 Suilven Ithaca SP E&P Limited 50.00% 0.00%
29/5b P.362 Elgin-Franklin TotalEnergies E&P UK Limited 6.09% 1.95%
21/4a P.347 Callanish Chrysaor Production (UK) Limited 13.70% 13.70%
16/27b P.345 Britannia Chrysaor Production (UK) Limited 35.75% 35.75%
9/11a P.335 Mariner Equinor UK Limited 8.89% 0.00%
13/22a P.324 Captain Ithaca Energy (UK) Limited 85.00% 85.00%
22/18a P.292 Arbroath, Arkwright, Carnoustie, Wood Repsol Sinopec Resources UK Limited 41.03% 0.00%
22/17s, 22/22a and 22/23a P.291 Arbroath, Arkwright, Brechin, Carnoustie, Cayley, Shaw Repsol Sinopec Resources UK Limited 41.03% 0.00%
23/26b P.264 Erskine Ithaca Energy (UK) Limited 50.00% 56.67%
9/11d and 9/12b P.2508 Mariner Equinor UK Limited 8.89% 0.00%
22/1b P.2373 F Block (Fotla and Fortriu) Ithaca Oil and Gas Limited 60.00% 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% 0.00%
16/26a P.213 Alba Ithaca Oil and Gas Limited 36.67% 36.67%
16/26a P.213 Britannia Ithaca MA Limited 33.17% 33.17%
16/26a P.213 N/A Ithaca Oil and Gas Limited 21.85% 21.85%
3/7a P.203 Columba E CNR International (UK) Limited 20.00% 0.00%
3/8a and 3/8a P.199 Columba B/D CNR International (UK) Limited 5.60% 0.00%
Group Net % Interest
Block Licence Field/Discovery Name Operator
2022 2021
22/30b P.188 Elgin-Franklin TotalEnergies E&P UK Limited 6.09% 3.04%
21/20a P.185 Cook Ithaca Energy (UK) Limited 61.35% 61.35%
8/15a P.1758 Mariner Equinor UK Limited 8.89% 0.00%
29/10b P.1665 Abigail Ithaca Energy (UK) Limited 100.00% 50.00%
30/7b P.1589 Jade Chrysaor Petroleum Company UK Limited 25.50% 9.97%
30/1f P.1588 Vorlich Ithaca Energy (UK) Limited 100.00% 100.00%
205/2a P.1272 Rosebank Equinor UK Limited 20.00% 0.00%
205/1a P.1191 Rosebank Equinor UK Limited 20.00% 0.00%
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 70.00% 0.00%
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.103 Britannia Chrysaor Production (UK) Limited 33.03% 33.03%
21/5a P.103 Enochdhu Chrysaor Production (UK) Limited 50.00% 50.00%
204/9a and 204/10a P.1028 Cambo Ithaca SP E&P Limited 70.00% 0.00%
213/26b and 213/27a P.1026 Rosebank Equinor UK Limited 20.00% 0.00%
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% 0.00%
22/17s, 22/22a and 22/23a P.019 Godwin, Montrose Repsol Sinopec Resources UK Limited 41.03% 0.00%
30/6a and 29/10a P.011 Stella/Harrier Ithaca Energy (UK) Limited 100.00% 100.00%
30/11a and 30/12d P.1820 Isabella Total Energies E&P North Sea UK Limited 10.00% 10.00%
204/8, 204/9c, 204/10c, 204/13, 204/14d
P.2403 Tornado Ithaca SP E&P Limited 50.00% 0.00%
and 204 /15
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfJointVenturesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-374": {
"value": "17. Business combinations
The fair values of the identifiable assets and liabilities as at the acquisition dates were:
MOGL
2022
US$\u2019000
Siccar
2022
US$\u2019000
Summit
2022
US$\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 cashflows relating to acquisition 62,818* (926,708) (100,563)
* Net cashflows relating to the MOGL acquisition includes a $7 million deposit paid in the year ended 31 December 2021.
The fair value of the financial assets includes trade and other receivables with a fair value of $78.8 million and an equal gross contractual value.
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 (\u201cSPA\u201d) 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\u202fJanuary\u202f2022 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 calculated at the acquisition date uses the same assumptions as set out in the critical accounting judgements section of note 3 and is subsequently revalued at the year end date.
From the date of acquisition, the MOGL assets have contributed $316 million of revenue and $199 million of profit before tax in 2022. Had the acquisition occurred on 1 January 2022, the MOGL assets would have contributed
$343\u202fmillion of revenue and $224 million of profit before tax for the 2022 financial year.
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 unable 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 20.00%, Cambo 70.00% and Tornado 50.00%) 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\u202fterms of the SPA.
The contingent consideration calculated at the acquisition date uses the same assumptions as set out in the critical accounting judgements section of note 3 and is subsequently revalued at the year end date.
From the date of acquisition, the Siccar Point Energy assets have contributed $184 million of revenue and $90 million of profit before tax in 2022. Had the acquisition occurred on 1 January 2022, the Siccar Point Energy assets
would\u202fhave contributed $337 million of revenue and a $128 million loss before tax for the 2022 financial year.
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 which were unable to be utilised by Siccar Point
Energy, 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 $200m 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 $25.6m 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 is 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 $62m 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.
From the date of acquisition, the Summit assets have contributed $52 million of revenue and $38 million of profit before tax in 2022. Had the acquisition occurred on 1 January 2022, the Summit assets would have contributed
$83\u202fmillion of revenue and $32 million of profit before tax for the 2022 financial year.
There are no contingent consideration arrangements under the Sale and Purchase Agreement of the Summit assets.
Mitsui
On 30 November 2021, the Group completed the acquisition of an additional 13.3% interest in the Alba field from Mitsui E&P UK Limited. The acquisition comprised property, plant and equipment of $22 million, a working capital
creditor of $11 million and a decommissioning provision of $55 million. This resulted in a reverse consideration being paid to the Group, as such the consideration owed from Mitsui to the Group was $55 million.
No contingent liabilities have been acquired on the business combinations detailed above.
The fair values of the oil and gas assets and the intangible assets acquired have been determined using valuation techniques based on discounted cash flows using forward curve commodity prices and estimates of long-term
commodity prices reflective of market conditions at each completion date, a discount rate based on observable market data and cost and production profiles generally consistent with the proved and probable reserves acquired
with each asset (see note 19 for further details). The decommissioning liabilities recognised have been estimated based on operator cost estimates with reference to observable market data.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBusinessCombinationsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-375": {
"value": "18. Goodwill 2022 US$\u2019000 2021 US$\u2019000 Balance at 1 January 722,075 722,075 Additions (note 17) 61,773 \u2013 Balance at 31 December 783,848 722,075 The goodwill is not tax deductible on any of the acquisitions. The opening goodwill of $722 million relates to historic business combinations. The goodwill on acquisition in the current period relates to the Summit acquisition, as detailed in note 17. Annual impairment tests were performed. The review was carried out on a fair value less cost of disposal basis using risk adjusted cash flow projections from the approved business plans including the same commodity prices, life of field cost profiles and production volumes used for impairment of oil and gas assets (see note 19), discounted at a post-tax discount rate of 10.9%. Assumptions and estimates in the Group impairment models are detailed in note 3. The CGU for the purposes of the goodwill test is the North Sea i.e. the entire Group portfolio of oil and gas assets which is consistent with the operating segment view of the business. The fair value estimate is categorised as level 3 in the fair value hierarchy. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfGoodwillExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-376": {
"value": "19. Impairment (charge)/reversal on oil and gas assets
2022
US$\u2019000
2021
US$\u2019000
D&P assets (30,700) 465,271
E&E assets (1,867) \u2013
Contingent consideration reversal 1,100 \u2013
North Sea oil and gas assets (31,467) 465,271
The impairment charge on D&P assets of $30.7 million in 2022 reflect revisions in decommissioning provisions, principally on fields that are no longer producing.
An impairment review was 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 (\u201cEPL\u201d) 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
discount rate
assumption
Price assumptions (nominal)
2023 2024 2025 2026 2027*
Oil 10.90% $89/bbl $84/bbl $83/bbl $83/bbl $83/bbl
Gas 10.90% 315p/therm 211p/therm 99p/therm 86p/therm 86p/therm
* post 2027 an annual 2% increase is applied to the price assumption
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 a post-tax impairment
of PP&E of $13 million at 31 December 2022. An increase of 1% in the discount rate assumption would not result in a post-tax impairment of PP&E. There would be no impairment of goodwill. A\u202fdecrease in discount rate or an
increase in forecast revenues would have no material impact on post-tax carrying amounts.
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. During 2021, the Group recorded a $465 million pre-tax impairment reversal relating to oil and gas assets. The review was driven by higher commodity price forward curves and was carried
out on a fair value less costs of disposal basis, resulting in pre-tax reversal of $397.3 million on Stella, $28.8 million on Alba and $33 million on Pierce, with related post-tax recoverable amounts of $565 million, $77 million and
$120\u202fmillion respectively. The remaining reversal of $6 million relates to revisions to decommissioning estimates for assets which have been fully impaired. The following assumptions were used at Q4 2021 in developing the cash
flow model and applied over the expected live of the respective fields:
Post-tax
discount rate
assumption
Price assumptions (nominal)
2022 2023 2024 2025 2026
Oil 9.50% $76/bbl $69/bbl $71/bbl $72/bbl $74/bbl
Gas 9.50% 164p/therm 99p/therm 68p/therm 61p/therm 56p/therm
Estimated production volumes and cash flows up to the date of cessation of production on a field by field basis, including operating and capital expenditure, are derived from the approved business plans and third party reports.
",
"dimensions": {
"concept": "ifrs-full:DisclosureOfImpairmentOfAssetsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-377": {
"value": "20. Borrowings 2022 US$\u2019000 2021 US$\u2019000 Current Amounts owed to related parties (note 32) \u2013 (437,076) \u2013 (437,076) Non-current RBL facility (600,000) (350,000) Senior unsecured notes (625,000) (625,000) Unamortised long-term bank fees 7,591 13,214 Unamortised long-term senior notes fees 3,678 7,170 Total debt (1,213,731) (954,616) Accrued interest on borrowings is included within accruals (note 22). Adjusted net debt 2022 US$\u2019000 2021 US$\u2019000 Total debt 1,213,731 1,391,692 Less cash and cash equivalents (253,822) (44,849) Adjusted net debt 959,909 1,346,843 Adjusted net debt does not include lease liabilities. Amounts owed to related parties In November 2019 the Group issued interest-free capital loan notes worth a nominal value of $392 million to a related Group undertaking, DKL Energy Limited. At the date of issuance, the capital loan notes were due for repayment no later than May 2022, after which point these were repayable on demand. On initial recognition, in November 2019, the capital loan notes were recorded at a fair value of $278m estimated based on a 15% market rate of interest. The difference between the two was recorded as a $114 million capital contribution (see note 26). The capital contribution was fully unwound as a result of a capital reduction in preparation for the IPO. Capital loan notes of $182\u202fmillion were waived (see note 32) with the balance of $210 million being repaid out of the proceeds of the IPO. The waived loan of $182 million has been capitalised as a Capital Contribution Reserve (see note 26). Subordinated loan In November 2019, the Group issued a subordinated loan note worth $198 million to the same Group undertaking, DKL Energy Limited. The interest terms up to May 2021 matched those of an external loan with BNP Paribas entered into by DKL Energy on which a margin ranging from 6.5% to 11.5% on LIBOR was charged. Subsequent to repayment of the BNP Paribas loan by DKL Energy in May 2021, the tracker loan note was interest free. The tracker loan note was due for repayment at the date of issuance no later than May 2022, after which it was repayable on demand. The Group prepaid $120m of the tracker loan note in 2020 and $15 million in 2021. The remaining balance was\u202frepaid out of proceeds of the IPO. Reserves Based Lending (RBL) facility During 2019, the Group\u2019s RBL facility size was increased to $1,650 million and its maturity was extended to April 2024, simultaneously an existing $300 million Term Loan was retired. The effective interest rate of the facility was 4.96%. Loan fees of $26.7 million relating to the RBL were capitalised in 2019 and amortised over the remaining life of the loan. In July 2021, the Group completed a further 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 2022, due to the NPV cap described in the covenants section below, the total availability was $925 million, of which $600 million was drawn down, leaving a further amount of $325 million being available for drawdown. Loan fees of $15.2 million relating to the RBL were capitalised and will be amortised over the term of the loan, $7.6 million remains to be amortised as at 31 December 2022. Following the refinancing $18.1 million of un-amortised fees were expensed to the statement of profit or loss in 2021, included within loan fee amortisation, relating to the previous RBL facility. 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 2022 was $6,760\u202fmillion (2021: $4,732 million). Senior notes During July 2019, the Group issued $500 million 9.375% senior unsecured notes due for repayment in July 2024 with interest payable semi-annually. Loan fees of $14.3 million relating to the senior notes were capitalised on issuance and amortised over the remaining life of the loan. In July 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, $3.7 million remains to be amortised as at 31 December 2022. Following the refinancing, $6 million of un-amortised fees were expensed, to the statement of profit or loss in 2021, included within loan fee amortisation relating to the previous senior notes. 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 redeemed on 12th October 2022 and there is no remaining balance as at 31 December 2022. Covenants in relation to these senior notes are detailed below. Covenants The Group is subject to financial and operating covenants related to the RBL facility. There are no covenants associated with amounts owed to related parties. 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 $625m 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: incur additional debt; 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 net debt to EBITDAX shall be less than 3.5:1. \u2018Net debt\u2019 referred to is not an IFRS measure. The Company uses net debt as a measure to assess its financial position. Net debt comprises amounts outstanding under the Company\u2019s RBL facility and senior notes, less cash and cash equivalents. Subordinated debt of $250m from Delek Group Limited which was repaid on 3 August 2021 is a treated as a parent company loan; \u2022 Total projected sources of funds must exceed the total projected uses of funds for the following 12 month period (or a longer period to first production from development, if applicable); \u2022 The ratio of the net present value of cash flows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1; and \u2022 The ratio of the net present value of cash flows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1. The Group was in compliance with all financial covenants of the RBL in all periods presented. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfBorrowingsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-378": {
"value": "21. Changes in liabilities arising from financing activities * 2022 US$\u2019000 2021 US$\u2019000 At 1 January (1,395,048) (1,855,773) Cash flows 377,198 650,736 Acquisitions (200,000) \u2013 Other (47,613) (190,011) At 31 December (1,265,463) (1,395,048) * being interest bearing loans, lease liabilities and interest rate derivatives. Other movement comprises mainly finance costs, capital contribution and related imputed interest. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCashFlowStatementExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-379": {
"value": "22. Trade and other payables 2022 US$\u2019000 2021 US$\u2019000 Trade payables (14,917) (13,901) Amounts owed to parent (note 32) \u2013 (43,408) Hydrocarbon amounts owed to joint ventures/overlift (124,365) (42,944) Other payables (185,720) (187,655) Accruals (299,604) (139,818) Deferred income (86,806) (56,542) (711,412) (484,268) The Directors consider the carrying values of trade and other payables to approximate the fair value. Other payables mainly comprises VAT liabilities and amounts owed due to production adjustments. Hydrocarbon amounts owed to joint ventures comprises hydrocarbon inventory overlift owed to partners. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfTradeAndOtherPayablesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-380": {
"value": "w 23. Decommissioning liabilities 2022 US$\u2019000 2021 US$\u2019000 Balance at 1 January (1,641,489) (1,416,236) Business combination additions (390,530) (55,429) Accretion (52,592) (42,502) Additions and revisions to estimates 298,564 (175,190) Decommissioning provision utilised 65,507 47,868 Balance, end of period (1,720,540) (1,641,489) Current Balance, beginning of period (94,640) (28,836) Balance, end of period (146,829) (94,640) Non-current Balance, beginning of period (1,546,849) (1,387,400) Balance, end of period (1,573,711) (1,546,849) 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 discount rate of 4.25 percent (31 December 2021: 2.5 percent) and an inflation rate of 2.0 percent (31 December 2021: 2.0 percent) 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 2022 and 2021 were due to changes in both cost estimates and discount rate\u202fassumptions. The estimated 2023 decommissioning spend of $147 million has been treated as a current liability as at 31 December 2022 (2021: $95 million). While the Group currently expects to incur decommissioning costs over the next 40\u202fyears, we anticipate that approximately 33% of the liability will be paid within the next five years. ",
"dimensions": {
"concept": "ithacaenergyplc:DisclosureOfDecommissioningLiabilities",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-381": {
"value": "24. Lease liabilities Current 2022 US$\u2019000 2021 US$\u2019000 Lease liability (41,637) (3,211) Non-Current 2022 US$\u2019000 2021 US$\u2019000 Lease liability (17,221) (278) The following table sets out a maturity analysis of lease payments, showing the undiscounted lease payments to be paid after the reporting date. All lease liabilities are fully payable within two years from 31 December 2022. 2022 US$\u2019000 2021 US$\u2019000 Less than one year (44,257) (2,094) One to two years (17,439) (1,617) Total undiscounted lease payments (61,696) (3,711) Future finance charges and other adjustments 2,838 222 Lease liabilities in the financial statements (58,858) (3,489) 2022 US$\u2019000 2021 US$\u2019000 At 1 January (3,489) (6,992) Additions (89,717) \u2013 Interest (3,852) (367) Payments 38,200 3,870 At 31 December (58,858) (3,489) Current (41,637) (3,211) Non-current (17,221) (278) (58,858) (3,489) The office lease was repaid in full during 2021. The addition in the year to 31 December 2022 relates to the Pioneer rig lease currently utilised on the Captain EOR project. The incremental borrowing rate applied to the lease is 6.07%. If the Company were to terminate the use of the Pioneer rig early then termination fees would apply, escalating to 75% of total expected costs if within 1 month prior to commencement date of planned works. Remuneration for work performed up to the date of termination, together with costs relating to demobilisation of the drilling unit to the demobilisation port would also be due. Amounts recognised in profit and loss related to leases is detailed in notes 6 and 9. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfLeasesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-382": {
"value": "25. Contingent and deferred consideration Current 2022 US$\u2019000 2021 US$\u2019000 Contingent consideration (101,559) \u2013 Petrofac deferred consideration (6,121) (49,806) (107,680) (49,806) Non-current 2022 US$\u2019000 2021 US$\u2019000 Contingent consideration (157,337) (19,480) Petrofac deferred consideration \u2013 (5,804) MOGL deferred consideration (61,783) \u2013 (219,120) (25,284) 2022 US$\u2019000 2021 US$\u2019000 Cash flows relating to contingent and deferred considerations (66,132) \u2013 Movement in contingent consideration and deferred consideration is as follows: 2022 US$\u2019000 2021 US$\u2019000 At 1 January (75,090) (67,114) Business combinations (note 17) (304,846) (13,530) Utilisation 66,132 \u2013 Reversal 1,100 \u2013 Accretion (9,801) (2,696) Changes in fair value (4,295) 8,250 At 31 December (326,800) (75,090) Cash outflows in the year ended 31 December 2022 of $66.1 million are in relation to the consideration payable on Petrofac GSA transaction and three quarterly payments in consideration to the MOGL oil price trigger. Petrofac The Petrofac deferred consideration relates to the completion of the GSA transaction in December 2018 and is payable over a period from 2020 to 2023 and is discounted to reflect the time value of money. Interest is payable at 5% on $15 million of the consideration. As part of the GSA transaction, Petrofac had the opportunity to earn up to an additional sum dependent on the future performance of the Stella and Harrier fields. $51.6 million was paid during 2022 in accordance with the Petrofac SPA. 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 2022, discounted at 4.25% was $128 million. The total undiscounted potential consideration as\u202fat 31 December 2022 is $241 million. The MOGL deferred consideration of $61.8 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 an interest in Siccar 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 2022, discounted at 4.25% was $102 million. The total undiscounted potential consideration as at 31 December 2022 is $362 million. Others $2.5 million of the non-current contingent consideration balance relates to the acquisition of the Vorlich field, with a remaining payment of $3.0 million due upon defined production criteria being met. $6.4 million relates to Yeoman/Marigold, with a remaining unrisked payment of $11.0 million contingent on achieving FDP and a further $6 million unrisked on certain production criteria being met. During the year ended 31 December 2022, further consideration of $6.4 million was recognised as an additional payable, resulting in $19.9 million (2021: $13.1 million) on Strathspey in accordance with the Sale and Purchase\u202fagreement. Revaluation of contingent consideration in the year to 31 December 2022 resulted in an increase of $4.3 million (2021: decrease of $8.3 million). 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, resulting in a reduction of $26.4 million or an equal and opposite increase to the contingent consideration respectively (2021: $nil). ",
"dimensions": {
"concept": "ithacaenergyplc:DisclosureOfContingentAndDeferredConsideration",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-383": {
"value": "26. Reserves (a) Issued share capital The issued share capital is as follows: Number of common shares Amount US$\u2019000 At 31 December 2021 1,001 1 At 31 December 2022 1,006,564,976 11,445 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 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, $0.01 B1 share and 0.01 B2 share to \u00a30.01 A ordinary shares 87,087 (12) (12) \u2013 87,063 Bonus Issue of new \u00a30.01 A shares 898,131,843 \u2013 \u2013 \u2013 898,131,843 Bonus Issue of new \u00a30.01 B1 shares \u2013 1,401,670 \u2013 \u2013 1,401,670 Bonus Issue of new \u00a30.01 B2 shares \u2013 \u2013 420,440 \u2013 420,440 Conversion of \u00a3 0.01 A ordinary shares, \u00a30.01 B1 shares and \u00a30.01 B2 shares to \u00a30.01 ordinary shares (898,219,931) (1,401,758) (420,528) 900,042,217 \u2013 Bonus issues of \u00a30.01 ordinary shares \u2013 \u2013 \u2013 120,000 120,000 Issue of new \u00a30.01 ordinary shares on IPO \u2013 \u2013 \u2013 105,000,000 105,000,000 Issue of new \u00a30.01 ordinary shares on exercise of share options \u2013 \u2013 \u2013 1,402,759 1,402,759 Ordinary shares of \u00a30.01 each at 31 December 2022 \u2013 \u2013 \u2013 1,006,564,976 1,006,564,976 (b) Share premium 2022 US$\u2019000 2021 US$\u2019000 Balance at 01 January 634,658 634,658 Share premium cancellation (634,658) \u2013 Addition 293,712 \u2013 Balance at 31 December 293,712 634,658 Addition during the year represents the difference between the nominal value of share \u00a30.01 and IPO price of \u00a32.50 per share (net of share issues expenses). (c) Capital contribution reserve (note 20) 2022 US$\u2019000 2021 US$\u2019000 Balance at 01 January 114,000 114,000 Capital reduction (114,000) \u2013 Addition 181,945 \u2013 Balance at 31 December 181,945 114,000 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 $181.9m has been capitalised as Capital Contribution Reserve as per the requirements of IFRS 9. (d) Share-based payment reserve 2022 US$\u2019000 2021 US$\u2019000 At 31 December 4,920 \u2013 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfShareCapitalReservesAndOtherEquityInterestExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-402": {
"value": "(a) Issued share capital The issued share capital is as follows: Number of common shares Amount US$\u2019000 At 31 December 2021 1,001 1 At 31 December 2022 1,006,564,976 11,445 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 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, $0.01 B1 share and 0.01 B2 share to \u00a30.01 A ordinary shares 87,087 (12) (12) \u2013 87,063 Bonus Issue of new \u00a30.01 A shares 898,131,843 \u2013 \u2013 \u2013 898,131,843 Bonus Issue of new \u00a30.01 B1 shares \u2013 1,401,670 \u2013 \u2013 1,401,670 Bonus Issue of new \u00a30.01 B2 shares \u2013 \u2013 420,440 \u2013 420,440 Conversion of \u00a3 0.01 A ordinary shares, \u00a30.01 B1 shares and \u00a30.01 B2 shares to \u00a30.01 ordinary shares (898,219,931) (1,401,758) (420,528) 900,042,217 \u2013 Bonus issues of \u00a30.01 ordinary shares \u2013 \u2013 \u2013 120,000 120,000 Issue of new \u00a30.01 ordinary shares on IPO \u2013 \u2013 \u2013 105,000,000 105,000,000 Issue of new \u00a30.01 ordinary shares on exercise of share options \u2013 \u2013 \u2013 1,402,759 1,402,759 Ordinary shares of \u00a30.01 each at 31 December 2022 \u2013 \u2013 \u2013 1,006,564,976 1,006,564,976 ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIssuedCapitalExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-384": {
"value": "27. Taxation 2022 US$\u2019000 2021 US$\u2019000 Current tax Current corporation tax (charge)/credit (185,946) 14,863 Current corporation tax credit \u2013 prior year 1,839 3,815 Total current tax (charge)/credit (184,107) 18,678 Deferred tax Adjustment in respect of prior period (641) (1,215) Group tax charge in consolidated statement of profit or loss (1,013,817) (386,767) Group tax (charge)/credit in consolidated statement of other comprehensive income (200,455) 194,632 Total deferred tax charge (1,214,913) (193,350) Deferred Petroleum Revenue Tax Deferred PRT (charge)/credit in statement of profit or loss (10,432) 32,154 Total Tax charge through consolidated statement of profit or loss (1,208,997) (337,150) The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows: 2022 US$\u2019000 2021 US$\u2019000 Accounting profit before tax 2,240,529 763,139 At tax rate of 40% (2021: 40%) (896,211) (305,256) Non-deductible expense (53,548) (71,996) Recognition of non-taxable gain on bargain purchase 534,069 \u2013 Financing costs not allowed for SCT (1,958) (2,499) Ring Fence Expenditure Supplement 155,113 11,313 Deferred tax effect of investment allowance (20,615) 9,735 Over provided in prior years 1,198 2,602 Net deferred PRT (6,259) 19,293 Deferred tax on EPL (766,489) \u2013 Current tax on EPL (131,389) \u2013 Prior year adjustments on acquired entities (3,165) \u2013 Unrecognised tax losses (19,743) (342) Total tax charge recorded in the consolidated statement of profit or loss (1,208,997) (337,150) The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in 2022, prior to the introduction of the EPL, was 40% (2021: 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. 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\u202fchanges 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: 2022 US$\u2019000 2021 US$\u2019000 Deferred corporation tax liability (2,258,813) (688,140) Deferred corporation tax asset 2,629,548 876,904 Deferred PRT asset 21,721 32,154 Net deferred tax asset 392,456 220,918 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. Non-oil and gas losses of $156 million, of which there is no expiry date, has not been recognised for deferred tax purposes as it is not certain that there will be future non-oil and gas profits to offset these losses. The net movement on the deferred tax account is as follows: 2022 US$\u2019000 2021 US$\u2019000 At 1 January 220,918 382,114 Profit or loss (charge) (1,024,889) (355,828) Other comprehensive income (charge)/credit (200,455) 194,632 Business combinations (note 17) 1,396,882 \u2013 At 31 December 392,456 220,918 The net movement on the deferred tax account through the consolidated statement of profit or loss relates to the following: 2022 US$\u2019000 2021 US$\u2019000 Accelerated capital allowances (490,246) (149,117) Tax losses (386,819) (218,174) Abandonment provision (124,598) 24,214 Petroleum revenue tax \u2013 (12,861) Deferred PRT 4,173 \u2013 Hedging (226,040) 152,015 Investment allowances 8,617 10,573 (1,214,913) (193,350) Gross deferred corporation tax liabilities Hedges US$000 Deferred corporation tax on deferred PRT US$000 Accelerated tax depreciation US$000 Total US$000 At 1 January 2021 26,941 \u2013 (536,735) (509,794) Reclass to deferred corporation tax assets (26,941) \u2013 \u2013 (26,941) Prior year adjustment \u2013 \u2013 (15,813) (15,813) Origination and reversal of temporary differences \u2013 (12,861) (122,731) (135,592) At 31 December 2021 \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) (647,743) Origination and reversal of temporary differences \u2013 4,173 (485,985) (481,812) At 31 December 2022 \u2013 (8,688) (2,250,125) (2,258,813) Gross deferred corporation tax assets Abandonment provision US$000 Tax losses US$000 Hedges US$000 Total US$000 At 1 January 2021 173,452 718,456 \u2013 891,908 Reclass from deferred corporation tax liabilities \u2013 \u2013 26,941 26,941 Prior year adjustment \u2013 14,599 \u2013 14,599 Origination and reversal of temporary differences 24,214 (232,773) 152,015 (56,544) At 31 December 2021 197,666 500,282 178,956 876,904 Prior year adjustment \u2013 3,706 \u2013 3,706 Reclassification of decommissioning asset 436,772 \u2013 \u2013 436,772 Business combinations 156,212 1,858,706 38,406 2,053,324 Origination and reversal of temporary differences (124,598) (390,520) (226,040) (741,158) At 31 December 2022 666,052 1,972,174 (8,678) 2,629,548 Deferred PRT asset Total $000 At 1 January 2021 \u2013 Profit or loss credit 32,154 At 31 December 2021 32,154 Origination and reversal of temporary differences (10,433) At 31 December 2022 21,721 The carrying value of the net deferred corporation tax asset at 31 December 2022 of $371 million (2021: $189 million) is 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 are undertaking a restructuring exercise which will result in certain assets being moved between Group entities. The recoverability of the deferred corporation tax asset is supported by this restructuring and a well-developed plan is in place to implement these changes. The DTA relating to losses within the Group are expected to unwind against taxable profits before the end of 2027. The Energy Profits Levy (EPL) was enacted on 14th 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 17th November 2022, the EPL was increased to 35% and extended to 31 March 2028 regardless of 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. The impact of the EPL is to increase the deferred tax liability by $780 million thereby reducing the overall deferred tax\u202fasset of the Group by $780 million. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfIncomeTaxExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-403": {
"value": "27. Taxation 2022 US$\u2019000 2021 US$\u2019000 Current tax Current corporation tax (charge)/credit (185,946) 14,863 Current corporation tax credit \u2013 prior year 1,839 3,815 Total current tax (charge)/credit (184,107) 18,678 Deferred tax Adjustment in respect of prior period (641) (1,215) Group tax charge in consolidated statement of profit or loss (1,013,817) (386,767) Group tax (charge)/credit in consolidated statement of other comprehensive income (200,455) 194,632 Total deferred tax charge (1,214,913) (193,350) Deferred Petroleum Revenue Tax Deferred PRT (charge)/credit in statement of profit or loss (10,432) 32,154 Total Tax charge through consolidated statement of profit or loss (1,208,997) (337,150) The tax on the Group\u2019s profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows: 2022 US$\u2019000 2021 US$\u2019000 Accounting profit before tax 2,240,529 763,139 At tax rate of 40% (2021: 40%) (896,211) (305,256) Non-deductible expense (53,548) (71,996) Recognition of non-taxable gain on bargain purchase 534,069 \u2013 Financing costs not allowed for SCT (1,958) (2,499) Ring Fence Expenditure Supplement 155,113 11,313 Deferred tax effect of investment allowance (20,615) 9,735 Over provided in prior years 1,198 2,602 Net deferred PRT (6,259) 19,293 Deferred tax on EPL (766,489) \u2013 Current tax on EPL (131,389) \u2013 Prior year adjustments on acquired entities (3,165) \u2013 Unrecognised tax losses (19,743) (342) Total tax charge recorded in the consolidated statement of profit or loss (1,208,997) (337,150) The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in 2022, prior to the introduction of the EPL, was 40% (2021: 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. 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\u202fchanges 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: 2022 US$\u2019000 2021 US$\u2019000 Deferred corporation tax liability (2,258,813) (688,140) Deferred corporation tax asset 2,629,548 876,904 Deferred PRT asset 21,721 32,154 Net deferred tax asset 392,456 220,918 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. Non-oil and gas losses of $156 million, of which there is no expiry date, has not been recognised for deferred tax purposes as it is not certain that there will be future non-oil and gas profits to offset these losses. The net movement on the deferred tax account is as follows: 2022 US$\u2019000 2021 US$\u2019000 At 1 January 220,918 382,114 Profit or loss (charge) (1,024,889) (355,828) Other comprehensive income (charge)/credit (200,455) 194,632 Business combinations (note 17) 1,396,882 \u2013 At 31 December 392,456 220,918 The net movement on the deferred tax account through the consolidated statement of profit or loss relates to the following: 2022 US$\u2019000 2021 US$\u2019000 Accelerated capital allowances (490,246) (149,117) Tax losses (386,819) (218,174) Abandonment provision (124,598) 24,214 Petroleum revenue tax \u2013 (12,861) Deferred PRT 4,173 \u2013 Hedging (226,040) 152,015 Investment allowances 8,617 10,573 (1,214,913) (193,350) Gross deferred corporation tax liabilities Hedges US$000 Deferred corporation tax on deferred PRT US$000 Accelerated tax depreciation US$000 Total US$000 At 1 January 2021 26,941 \u2013 (536,735) (509,794) Reclass to deferred corporation tax assets (26,941) \u2013 \u2013 (26,941) Prior year adjustment \u2013 \u2013 (15,813) (15,813) Origination and reversal of temporary differences \u2013 (12,861) (122,731) (135,592) At 31 December 2021 \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) (647,743) Origination and reversal of temporary differences \u2013 4,173 (485,985) (481,812) At 31 December 2022 \u2013 (8,688) (2,250,125) (2,258,813) Gross deferred corporation tax assets Abandonment provision US$000 Tax losses US$000 Hedges US$000 Total US$000 At 1 January 2021 173,452 718,456 \u2013 891,908 Reclass from deferred corporation tax liabilities \u2013 \u2013 26,941 26,941 Prior year adjustment \u2013 14,599 \u2013 14,599 Origination and reversal of temporary differences 24,214 (232,773) 152,015 (56,544) At 31 December 2021 197,666 500,282 178,956 876,904 Prior year adjustment \u2013 3,706 \u2013 3,706 Reclassification of decommissioning asset 436,772 \u2013 \u2013 436,772 Business combinations 156,212 1,858,706 38,406 2,053,324 Origination and reversal of temporary differences (124,598) (390,520) (226,040) (741,158) At 31 December 2022 666,052 1,972,174 (8,678) 2,629,548 Deferred PRT asset Total $000 At 1 January 2021 \u2013 Profit or loss credit 32,154 At 31 December 2021 32,154 Origination and reversal of temporary differences (10,433) At 31 December 2022 21,721 The carrying value of the net deferred corporation tax asset at 31 December 2022 of $371 million (2021: $189 million) is 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 are undertaking a restructuring exercise which will result in certain assets being moved between Group entities. The recoverability of the deferred corporation tax asset is supported by this restructuring and a well-developed plan is in place to implement these changes. The DTA relating to losses within the Group are expected to unwind against taxable profits before the end of 2027. The Energy Profits Levy (EPL) was enacted on 14th 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 17th November 2022, the EPL was increased to 35% and extended to 31 March 2028 regardless of 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. The impact of the EPL is to increase the deferred tax liability by $780 million thereby reducing the overall deferred tax\u202fasset of the Group by $780 million. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfDeferredTaxesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-385": {
"value": "28. Commitments and contingencies 2022 US$\u2019000 2021 US$\u2019000 Capital commitments Capital commitments incurred jointly with other venturers (Group\u2019s share) 52,309 83,368 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 2022, the Group had commitments for future capital expenditure amounting to $52.3 million. The key components of this relate to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction, platform abandonment on Anglia and drilling at the Shaw field. As of 31 December 2021, the Group had commitments for future capital expenditure amounting to $83.4 million. The key components of this relate to the Captain enhanced oil recovery programme, investments on the Abigail field and upgrade works planned on Jade and Pierce. Contingencies The Group enters into letters of credit and surety bonds to provide security for the Group\u2019s obligations under certain field and bi-lateral decommissioning security agreements, or equivalent, Sullom Voe Terminal Tariff Agreements and deferred payment obligations. The instruments are either held by the Law Debenture Trust Corporation P.L.C. under a trust deed or EnQuest Heather Limited, as SVT Terminal Operator. At 31 December 2021 and 2022, the Group had \u00a3341 million and \u00a3383 million, respectively, in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfCommitmentsAndContingentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-412": {
"value": "28. Commitments and contingencies 2022 US$\u2019000 2021 US$\u2019000 Capital commitments Capital commitments incurred jointly with other venturers (Group\u2019s share) 52,309 83,368 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 2022, the Group had commitments for future capital expenditure amounting to $52.3 million. The key components of this relate to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction, platform abandonment on Anglia and drilling at the Shaw field. As of 31 December 2021, the Group had commitments for future capital expenditure amounting to $83.4 million. The key components of this relate to the Captain enhanced oil recovery programme, investments on the Abigail field and upgrade works planned on Jade and Pierce. Contingencies The Group enters into letters of credit and surety bonds to provide security for the Group\u2019s obligations under certain field and bi-lateral decommissioning security agreements, or equivalent, Sullom Voe Terminal Tariff Agreements and deferred payment obligations. The instruments are either held by the Law Debenture Trust Corporation P.L.C. under a trust deed or EnQuest Heather Limited, as SVT Terminal Operator. At 31 December 2021 and 2022, the Group had \u00a3341 million and \u00a3383 million, respectively, in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfContingentLiabilitiesExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-404": {
"value": "28. Commitments and contingencies 2022 US$\u2019000 2021 US$\u2019000 Capital commitments Capital commitments incurred jointly with other venturers (Group\u2019s share) 52,309 83,368 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 2022, the Group had commitments for future capital expenditure amounting to $52.3 million. The key components of this relate to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction, platform abandonment on Anglia and drilling at the Shaw field. As of 31 December 2021, the Group had commitments for future capital expenditure amounting to $83.4 million. The key components of this relate to the Captain enhanced oil recovery programme, investments on the Abigail field and upgrade works planned on Jade and Pierce. 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 2021 and 2022, the Group had \u00a3341 million and \u00a3383 million, respectively, 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": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-405": {
"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. 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 2022 are set out below: Measured at amortised cost $\u2019000 Mandatorily measured at fair value through profit or loss $\u2019000 Derivatives designated in hedge relationships $\u2019000 Total carrying amount $\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 (67,904) (258,896) \u2013 (326,800) Derivative financial instruments \u2013 (57,546) (106,563) (164,109) (1,596,093) The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2021 are set out below: Measured at amortised cost $\u2019000 Mandatorily measured at fair value through profit or loss $\u2019000 Derivatives designated in hedge relationships $\u2019000 Total carrying amount $\u2019000 Financial assets Cash and cash equivalents 44,849 \u2013 \u2013 44,849 Trade and other receivables 228,290 \u2013 \u2013 228,290 Derivative financial instruments \u2013 \u2013 5,108 5,108 Financial liabilities Borrowings (1,391,692) \u2013 \u2013 (1,391,692) Trade and other payables (427,726) \u2013 \u2013 (427,726) Lease liability (3,489) \u2013 \u2013 (3,489) Contingent and deferred consideration (19,480) (55,610) \u2013 (75,090) Derivative financial instruments \u2013 (2,009) (457,293) (459,302) (2,079,052) The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as of 31 December 2022: Level 1 US$\u2019000 Level 2 US$\u2019000 Level 3 US$\u2019000 Total Fair Value US$\u2019000 Contingent consideration (note 25) \u2013 (35,650) (223,246) (258,896 ) Derivative financial instrument asset \u2013 172,049 \u2013 172,049 Derivative financial instrument liability \u2013 (164,109) \u2013 (164,109) Movement in level 3 financial instruments in the 12 months to 31 December 2022 is as follows: US$\u2019000 At 1 January 2022 (19,480) Business combinations (210,096) Reversal 1,100 Accretion (5,208) Changes in fair value 10,438 At 31 December 2022 (223,246) The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as of 31 December 2021: Level 1 US$\u2019000 Level 2 US$\u2019000 Level 3 US$\u2019000 Total Fair Value US$\u2019000 Contingent consideration (note 25) \u2013 \u2013 (19,480) (19,480) Derivative financial instrument asset \u2013 5,108 \u2013 5,108 Derivative financial instrument liability \u2013 (459,302) \u2013 (459,302) Movement in level 3 financial instruments in the 12 months to 31 December 2021 is as follows: US$\u2019000 At 1 January 2021 (14,200) Additions (13,530) Changes in fair value 8,250 At 31 December 2022 (19,480) The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of profit or loss: 2022 US$\u2019000 2021 US$\u2019000 Revaluation of forex forward contracts (28,172) (8,261) Revaluation of commodity hedges 44,959 \u2013 16,787 (8,261) Realised (loss)/gain on commodity hedges (16,215) 7,808 Total gain/(loss) on financial instruments 572 (453) ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfFairValueMeasurementExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-386": {
"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. 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 2022 are set out below: Measured at amortised cost $\u2019000 Mandatorily measured at fair value through profit or loss $\u2019000 Derivatives designated in hedge relationships $\u2019000 Total carrying amount $\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 (67,904) (258,896) \u2013 (326,800) Derivative financial instruments \u2013 (57,546) (106,563) (164,109) (1,596,093) The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2021 are set out below: Measured at amortised cost $\u2019000 Mandatorily measured at fair value through profit or loss $\u2019000 Derivatives designated in hedge relationships $\u2019000 Total carrying amount $\u2019000 Financial assets Cash and cash equivalents 44,849 \u2013 \u2013 44,849 Trade and other receivables 228,290 \u2013 \u2013 228,290 Derivative financial instruments \u2013 \u2013 5,108 5,108 Financial liabilities Borrowings (1,391,692) \u2013 \u2013 (1,391,692) Trade and other payables (427,726) \u2013 \u2013 (427,726) Lease liability (3,489) \u2013 \u2013 (3,489) Contingent and deferred consideration (19,480) (55,610) \u2013 (75,090) Derivative financial instruments \u2013 (2,009) (457,293) (459,302) (2,079,052) The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as of 31 December 2022: Level 1 US$\u2019000 Level 2 US$\u2019000 Level 3 US$\u2019000 Total Fair Value US$\u2019000 Contingent consideration (note 25) \u2013 (35,650) (223,246) (258,896 ) Derivative financial instrument asset \u2013 172,049 \u2013 172,049 Derivative financial instrument liability \u2013 (164,109) \u2013 (164,109) Movement in level 3 financial instruments in the 12 months to 31 December 2022 is as follows: US$\u2019000 At 1 January 2022 (19,480) Business combinations (210,096) Reversal 1,100 Accretion (5,208) Changes in fair value 10,438 At 31 December 2022 (223,246) The following table presents the Group\u2019s material financial instruments measured at fair value for each hierarchy level as of 31 December 2021: Level 1 US$\u2019000 Level 2 US$\u2019000 Level 3 US$\u2019000 Total Fair Value US$\u2019000 Contingent consideration (note 25) \u2013 \u2013 (19,480) (19,480) Derivative financial instrument asset \u2013 5,108 \u2013 5,108 Derivative financial instrument liability \u2013 (459,302) \u2013 (459,302) Movement in level 3 financial instruments in the 12 months to 31 December 2021 is as follows: US$\u2019000 At 1 January 2021 (14,200) Additions (13,530) Changes in fair value 8,250 At 31 December 2022 (19,480) The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of profit or loss: 2022 US$\u2019000 2021 US$\u2019000 Revaluation of forex forward contracts (28,172) (8,261) Revaluation of commodity hedges 44,959 \u2013 16,787 (8,261) Realised (loss)/gain on commodity hedges (16,215) 7,808 Total gain/(loss) on financial instruments 572 (453) Hedging reserve The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of comprehensive income: Hedging reserve 2022 US$\u2019000 2021 US$\u2019000 Revaluation gain/(loss) of derivative contracts 492,900 (371,213) Realised loss on derivative contracts (582,445) (360,629) Amounts recycled to revenue 501,513 196,181 Amounts recycled to revenue \u2013 oil put premiums 14,629 27,179 Amounts recycled to revenue \u2013 gas put premiums 42,347 14,627 Amounts recycled to finance costs \u2013 interest put premiums (851) 7,276 Total gain/(loss) 468,093 (486,579) 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 purchases. Because the critical terms (i.e. the quantity, maturity and underlying) 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 2022 year end: Derivative Term Volume Average price Oil puts n/a \u2013 bbls n/a 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 below represents total commodity hedges in place at the 2021 year end: Derivative Term Volume Average price Oil puts Jan 22 \u2013 Dec 22 2,080,500 bbls $64/bbl Oil swaps Jan 22 \u2013 Dec 23 4,851,984 bbls $56/bbl Oil collars Jan 22 \u2013 Dec 23 3,558,750 bbls $58/bbl floor \u2013 $80/bbl ceiling Gas swaps Jan 22 \u2013 Dec 22 203,900,000 therms 64p/therm Gas puts Jan 22 \u2013 Dec 23 36,500,000 therms 40p/therm Gas collars Jan 22 \u2013 Dec 23 73,000,000 therms 60p/therm floor \u2013 94p/therm ceiling The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in realised commodity price 2022 US$\u2019000 2021 US$\u2019000 20% decrease in realised oil price (246,914) (271,610) 20% decrease in realised gas price (330,285) (144,905) 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 Facilities 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. Management have considered the impact of the IBOR reform on historic interest rate swaps and do not consider this to present significant additional risk to the Group and as such, have started a process to agree a transition with the interest rate swap counterparties to reduce any future impact on the financial statements after the 2023 transition date. 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 below represents interest rate financial instruments in place at the 2021 year end: Derivative Term Value Rate Interest rate swap (floating to fixed) Jan 21 \u2013 Dec 23 $50 million 0.22% The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. Change in interest rate 2022 US$\u2019000 2021 US$\u2019000 Increase of 250 basis points (11,126) (15,377) 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-USD amounts and on balance sheet translation of monetary accounts denominated in non-USD amounts upon spot rate fluctuations from quarter to quarter. 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 2021 the Group had an average of \u00a316 million per quarter hedged at an average forward rate of $1.375:\u00a31 for the period January to December 2022. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is not material. Change in GBP foreign exchange rate 2022 US$\u2019000 2021 US$\u2019000 10% weakening of GBP against USD (139,633) (33,915) A 10% strengthening of GBP against USD 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 Group\u2019s accounts receivable 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, Abigail and the MonArb fields is sold to ENI, Columba is sold to Repsol, Mariner to Equinor ASA, Schiehallion and Pierce to Shell International Trading, and Captain, Alba, Cook and Forties fields to BP Oil International. Forties fields, Stella, Vorlich, Jade and Abigail gas is sold to BP Gas Marketing. The agreement to sell Vorlich gas to Gazprom was terminated with effect from 30 September 2022 and production from these fields has subsequently been sold to BP Gas Marketing. Cook gas is sold to Shell International Trading and Esso Exploration, Schiehallion to EnQuest, and gas production from the MonArb fields is sold to Axpo Solutions AG. 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 2022, 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 2022 (31 December 2021: $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 2022, the Group\u2019s exposure is $nil (31 December 2021: $5.0 million). Judgements made in relation to the recognition of CVA/DVA can be found in note 3. The Group also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values. v) Liquidity risk Liquidity risk includes the risk that as a result of its operational liquidity requirements the Group will not have sufficient funds to settle a transaction on the due date. The Group manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Group considers the maturity profiles of its financial assets and liabilities. As at 31 December 2021 and 2022 substantially all accounts payable are current. The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2022: Within 1 year US$\u2019000 Within 2 to 5 years US$\u2019000 More than 5 Years US$\u2019000 Trade and other payables (618,460) \u2013 \u2013 Derivatives (136,668) (27,440) \u2013 Contingent and deferred consideration (116,518) (279,780) \u2013 Lease liabilities (44,257) (17,439) \u2013 Borrowings (56,250) (1,382,411) \u2013 (972,153) (1,707,070) \u2013 The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2021: Within 1 year US$\u2019000 Within 2 to 5 years US$\u2019000 More than 5 years US$\u2019000 Trade and other payables (484,268) \u2013 \u2013 Derivatives (438,006) (21,296) \u2013 Contingent and deferred consideration (49,806) (25,284) \u2013 Lease liabilities (2,094) (1,617) \u2013 Borrowings (437,076) (1,025,435) \u2013 (1,411,250) (1,073,632) \u2013 vi) Capital management The Group\u2019s objectives when managing capital are to safeguard the Group\u2019s ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required. The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates eroding the Group\u2019s financial results. ",
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},
"fact-406": {
"value": "Hedging reserve The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of comprehensive income: Hedging reserve 2022 US$\u2019000 2021 US$\u2019000 Revaluation gain/(loss) of derivative contracts 492,900 (371,213) Realised loss on derivative contracts (582,445) (360,629) Amounts recycled to revenue 501,513 196,181 Amounts recycled to revenue \u2013 oil put premiums 14,629 27,179 Amounts recycled to revenue \u2013 gas put premiums 42,347 14,627 Amounts recycled to finance costs \u2013 interest put premiums (851) 7,276 Total gain/(loss) 468,093 (486,579) ",
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}
},
"fact-407": {
"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 purchases. Because the critical terms (i.e. the quantity, maturity and underlying) 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 2022 year end: Derivative Term Volume Average price Oil puts n/a \u2013 bbls n/a 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 below represents total commodity hedges in place at the 2021 year end: Derivative Term Volume Average price Oil puts Jan 22 \u2013 Dec 22 2,080,500 bbls $64/bbl Oil swaps Jan 22 \u2013 Dec 23 4,851,984 bbls $56/bbl Oil collars Jan 22 \u2013 Dec 23 3,558,750 bbls $58/bbl floor \u2013 $80/bbl ceiling Gas swaps Jan 22 \u2013 Dec 22 203,900,000 therms 64p/therm Gas puts Jan 22 \u2013 Dec 23 36,500,000 therms 40p/therm Gas collars Jan 22 \u2013 Dec 23 73,000,000 therms 60p/therm floor \u2013 94p/therm ceiling The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in realised commodity price 2022 US$\u2019000 2021 US$\u2019000 20% decrease in realised oil price (246,914) (271,610) 20% decrease in realised gas price (330,285) (144,905) 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 Facilities 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. Management have considered the impact of the IBOR reform on historic interest rate swaps and do not consider this to present significant additional risk to the Group and as such, have started a process to agree a transition with the interest rate swap counterparties to reduce any future impact on the financial statements after the 2023 transition date. 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 below represents interest rate financial instruments in place at the 2021 year end: Derivative Term Value Rate Interest rate swap (floating to fixed) Jan 21 \u2013 Dec 23 $50 million 0.22% The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. Change in interest rate 2022 US$\u2019000 2021 US$\u2019000 Increase of 250 basis points (11,126) (15,377) 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-USD amounts and on balance sheet translation of monetary accounts denominated in non-USD amounts upon spot rate fluctuations from quarter to quarter. 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 2021 the Group had an average of \u00a316 million per quarter hedged at an average forward rate of $1.375:\u00a31 for the period January to December 2022. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is not material. Change in GBP foreign exchange rate 2022 US$\u2019000 2021 US$\u2019000 10% weakening of GBP against USD (139,633) (33,915) A 10% strengthening of GBP against USD 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 Group\u2019s accounts receivable 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, Abigail and the MonArb fields is sold to ENI, Columba is sold to Repsol, Mariner to Equinor ASA, Schiehallion and Pierce to Shell International Trading, and Captain, Alba, Cook and Forties fields to BP Oil International. Forties fields, Stella, Vorlich, Jade and Abigail gas is sold to BP Gas Marketing. The agreement to sell Vorlich gas to Gazprom was terminated with effect from 30 September 2022 and production from these fields has subsequently been sold to BP Gas Marketing. Cook gas is sold to Shell International Trading and Esso Exploration, Schiehallion to EnQuest, and gas production from the MonArb fields is sold to Axpo Solutions AG. 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 2022, 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 2022 (31 December 2021: $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 2022, the Group\u2019s exposure is $nil (31 December 2021: $5.0 million). Judgements made in relation to the recognition of CVA/DVA can be found in note 3. The Group also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values. v) Liquidity risk Liquidity risk includes the risk that as a result of its operational liquidity requirements the Group will not have sufficient funds to settle a transaction on the due date. The Group manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Group considers the maturity profiles of its financial assets and liabilities. As at 31 December 2021 and 2022 substantially all accounts payable are current. The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2022: Within 1 year US$\u2019000 Within 2 to 5 years US$\u2019000 More than 5 Years US$\u2019000 Trade and other payables (618,460) \u2013 \u2013 Derivatives (136,668) (27,440) \u2013 Contingent and deferred consideration (116,518) (279,780) \u2013 Lease liabilities (44,257) (17,439) \u2013 Borrowings (56,250) (1,382,411) \u2013 (972,153) (1,707,070) \u2013 The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2021: Within 1 year US$\u2019000 Within 2 to 5 years US$\u2019000 More than 5 years US$\u2019000 Trade and other payables (484,268) \u2013 \u2013 Derivatives (438,006) (21,296) \u2013 Contingent and deferred consideration (49,806) (25,284) \u2013 Lease liabilities (2,094) (1,617) \u2013 Borrowings (437,076) (1,025,435) \u2013 (1,411,250) (1,073,632) \u2013 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. ",
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"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-413": {
"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 purchases. Because the critical terms (i.e. the quantity, maturity and underlying) 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 2022 year end: Derivative Term Volume Average price Oil puts n/a \u2013 bbls n/a 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 below represents total commodity hedges in place at the 2021 year end: Derivative Term Volume Average price Oil puts Jan 22 \u2013 Dec 22 2,080,500 bbls $64/bbl Oil swaps Jan 22 \u2013 Dec 23 4,851,984 bbls $56/bbl Oil collars Jan 22 \u2013 Dec 23 3,558,750 bbls $58/bbl floor \u2013 $80/bbl ceiling Gas swaps Jan 22 \u2013 Dec 22 203,900,000 therms 64p/therm Gas puts Jan 22 \u2013 Dec 23 36,500,000 therms 40p/therm Gas collars Jan 22 \u2013 Dec 23 73,000,000 therms 60p/therm floor \u2013 94p/therm ceiling The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. Change in realised commodity price 2022 US$\u2019000 2021 US$\u2019000 20% decrease in realised oil price (246,914) (271,610) 20% decrease in realised gas price (330,285) (144,905) 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 Facilities 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. Management have considered the impact of the IBOR reform on historic interest rate swaps and do not consider this to present significant additional risk to the Group and as such, have started a process to agree a transition with the interest rate swap counterparties to reduce any future impact on the financial statements after the 2023 transition date. 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 below represents interest rate financial instruments in place at the 2021 year end: Derivative Term Value Rate Interest rate swap (floating to fixed) Jan 21 \u2013 Dec 23 $50 million 0.22% The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. Change in interest rate 2022 US$\u2019000 2021 US$\u2019000 Increase of 250 basis points (11,126) (15,377) 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-USD amounts and on balance sheet translation of monetary accounts denominated in non-USD amounts upon spot rate fluctuations from quarter to quarter. 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 2021 the Group had an average of \u00a316 million per quarter hedged at an average forward rate of $1.375:\u00a31 for the period January to December 2022. The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group\u2019s profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group\u2019s exposure to foreign currency changes for all other currencies is not material. Change in GBP foreign exchange rate 2022 US$\u2019000 2021 US$\u2019000 10% weakening of GBP against USD (139,633) (33,915) A 10% strengthening of GBP against USD would have had the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant. ",
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}
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"fact-414": {
"value": "iv) Credit risk The Group\u2019s accounts receivable 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, Abigail and the MonArb fields is sold to ENI, Columba is sold to Repsol, Mariner to Equinor ASA, Schiehallion and Pierce to Shell International Trading, and Captain, Alba, Cook and Forties fields to BP Oil International. Forties fields, Stella, Vorlich, Jade and Abigail gas is sold to BP Gas Marketing. The agreement to sell Vorlich gas to Gazprom was terminated with effect from 30 September 2022 and production from these fields has subsequently been sold to BP Gas Marketing. Cook gas is sold to Shell International Trading and Esso Exploration, Schiehallion to EnQuest, and gas production from the MonArb fields is sold to Axpo Solutions AG. 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 2022, 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 2022 (31 December 2021: $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 2022, the Group\u2019s exposure is $nil (31 December 2021: $5.0 million). Judgements made in relation to the recognition of CVA/DVA can be found in note 3. The Group also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values. ",
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"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-415": {
"value": "v) Liquidity risk Liquidity risk includes the risk that as a result of its operational liquidity requirements the Group will not have sufficient funds to settle a transaction on the due date. The Group manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Group considers the maturity profiles of its financial assets and liabilities. As at 31 December 2021 and 2022 substantially all accounts payable are current. The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2022: Within 1 year US$\u2019000 Within 2 to 5 years US$\u2019000 More than 5 Years US$\u2019000 Trade and other payables (618,460) \u2013 \u2013 Derivatives (136,668) (27,440) \u2013 Contingent and deferred consideration (116,518) (279,780) \u2013 Lease liabilities (44,257) (17,439) \u2013 Borrowings (56,250) (1,382,411) \u2013 (972,153) (1,707,070) \u2013 The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2021: Within 1 year US$\u2019000 Within 2 to 5 years US$\u2019000 More than 5 years US$\u2019000 Trade and other payables (484,268) \u2013 \u2013 Derivatives (438,006) (21,296) \u2013 Contingent and deferred consideration (49,806) (25,284) \u2013 Lease liabilities (2,094) (1,617) \u2013 Borrowings (437,076) (1,025,435) \u2013 (1,411,250) (1,073,632) \u2013 ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-416": {
"value": "vi) Capital management The Group\u2019s objectives when managing capital are to safeguard the Group\u2019s ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required. The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates eroding the Group\u2019s financial results. ",
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"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-387": {
"value": "30. Derivative financial instruments 2022 US$\u2019000 2021 US$\u2019000 Oil swaps \u2013 cash flow hedge (28,685) (102,704) Oil swaps \u2013 non-cash flow hedge (15,027) \u2013 Oil collars \u2013 cash flow hedge (21,983) (6,542) Oil puts \u2013 cash flow hedge \u2013 (9,402) Gas swaps \u2013 cash flow hedge 19,797 (264,345) Gas swaps \u2013 non-cash flow hedge (29,271) \u2013 Gas puts \u2013 cash flow hedge 9,746 (3,317) Gas collars \u2013 cash flow hedge 79,489 (66,007) Interest rate swaps \u2013 cash flow hedge \u2013 133 Interest rate swaps \u2013 non-cash flow hedge 7,125 \u2013 FX forwards \u2013 non-cash flow hedge (13,250) (2,010) 7,941 (454,194) Maturity analysis of derivative financial instruments 2022 US$\u2019000 2021 US$\u2019000 Non-current assets 21,191 133 Current assets 150,858 4,975 Non-current liabilities (27,440) (21,296) Current liabilities (136,668) (438,006) 7,941 (454,194) Judgements and estimates applied in the valuation of derivative instruments can be found in note 3. Derivative financial instruments that are with counterparties included within the RBL are subject to Master Netting Agreements. ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-388": {
"value": "31. Fair values of financial assets and liabilities Financial instruments of the Group consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in the financial statements. At 31 December the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows: Classification 2022 US$\u2019000 2021 US$\u2019000 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (held for trading) 253,822 253,822 44,849 44,849 Trade and other receivables 359,994 359,994 18,918 18,918 Derivative financial instruments 172,049 172,049 5,108 5,108 Deposits 9,055 9,055 10,536 10,536 Bank debt (loans and bonds) (1,213,731) (1,257,885) (329,616) (312,741) Trade and other payables (618,460) (618,460) (13,901) (13,901) Contingent and deferred consideration (326,800) (326,800) (75,090) (75,090) Derivative financial instruments (164,109) (164,109) (459,302) (459,302) Lease liabilities (58,858) (58,858) (3,489) (3,489) ",
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"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
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"fact-389": {
"value": "32. Related party transactions
The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) who owns 89.24% 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 Yitzhak (Sharon) Tshuva.
The consolidated financial statements include the financial information of the Group and the subsidiaries listed in the following table:
Registered office Country of incorporation
% equity interest at 31 December
2022 2021
Ithaca Energy (E&P) Limited (formerly Ithaca Energy Inc.) 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 (formerly Chevron North Sea 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 SPL Limited*** 4 England and Wales \u2013 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% \u2013
Ithaca SP Bonds PLC (formerly Siccar Point Energy Bonds PLC)** 4 England and Wales 100% \u2013
Ithaca SP Finance Limited (formerly Siccar Point Energy Finance Limited)** 4 England and Wales 100% \u2013
Ithaca SP (Holdings) Limited (formerly Siccar Point Energy (Holdings) Limited)** 4 England and Wales 100% \u2013
Registered office Country of incorporation % equity interest at 31 December 2022 2021 Ithaca SP (E&P) Limited (formerly Siccar Point Energy E&P Limited)** 4 England and Wales 100% \u2013 Ithaca SP (O&G) Limited (formerly Siccar Point Energy UK Limited)** 4 England and Wales 100% \u2013 Ithaca SPE Limited (formerly Siccar Point Energy Limited)** 4 England and Wales 100% \u2013 Ithaca Zeta Limited (formerly Summit Exploration and Production Limited)** 4 England and Wales 100% \u2013 Transactions between subsidiaries are eliminated on consolidation. * The Group acquired 100% of the share capital of Ithaca MA Limited (formerly Marubeni Oil & Gas (UK) Limited) on 4 February 2022. Further details on the acquisition are set out in note 17. ** The Group acquired 100% of the share capital of Ithaca SP Bonds PLC, Ithaca SP Finance Limited, Ithaca SP (Holdings Limited), Ithaca SP (E&P) Limited, Ithaca SP (O&G) Limited, Ithaca SP UK Limited, Ithaca SPE Limited and Ithaca Zeta Limited on 30 June 2022. Further details on the acquisitions are set out in note 17. *** Ithaca SPL Limited was dissolved on 15 February 2022. 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 The following table provides the loan balances with related parties as of 31 December: Borrowings \u2013 principal amount (note 20) 2022 US$\u2019000 2021 US$\u2019000 Subordinated loan due to DKL Energy Limited \u2013 (63,000) Capital Notes issued to DKL Energy Limited \u2013 (374,076) \u2013 (437,076) Amounts due to parent (note 22) 2022 US$\u2019000 2021 US$\u2019000 Delek Group Limited \u2013 (28,941) Subordinated loan due to DKL Energy Limited \u2013 (14,090) Other amounts owed to parent \u2013 (377) \u2013 (43,408) The outstanding interest of $29 million with respect to the 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 (note 20) and subsequent settlement of the $392 million balance under the waiver agreement as detailed below. 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 the Capital Note and subordinated Loan balances (including interest) totalling $469 million, such that, post IPO these balances would no longer be due from Ithaca Energy plc. The following table provides breakdown of amounts settled under the waiver agreement:
Status of outstanding loans as of 8 November 2022
Outstanding
Balance
US$\u2019000
Repayment
of loans
US$\u2019000
Loan Waiver
US$\u2019000
Subordinated loan due to DKL Energy Limited (63,000) 63,000 \u2013
Subordinated loan due to DKL Energy Limited (interest) (14,406) 14,406 \u2013
Capital Notes issued to DKL Energy Limited (392,000) 210,055 (181,945)
(469,406) 287,461 (181,945)
The loan waiver of $181.9 million was recognised as a Capital Contribution on equity.
The following table provides remuneration to key management personnel, being persons having direct or indirect authority or responsibility of the Group, for the periods ended 31 December 2022 and 2021:
Key management personnel
2022
US$\u2019000
2021
US$\u2019000
Salaries and short-term employee benefits 4,590 3,136
Payments made in lieu of pension contributions 229 112
Company pension contributions 106 155
Share-based payment 12,623 \u2013
17,548 3,403
Further detail regarding share-based payments received by key management personnel is set out below.
",
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"fact-408": {
"value": "32. Related party transactions The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) who owns 89.24% 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 Yitzhak (Sharon) Tshuva. The consolidated financial statements include the financial information of the Group and the subsidiaries listed in the following table: Registered office Country of incorporation % equity interest at 31 December 2022 2021 Ithaca Energy (E&P) Limited (formerly Ithaca Energy Inc.) 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 (formerly Chevron North Sea 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 SPL Limited*** 4 England and Wales \u2013 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% \u2013 Ithaca SP Bonds PLC (formerly Siccar Point Energy Bonds PLC)** 4 England and Wales 100% \u2013 Ithaca SP Finance Limited (formerly Siccar Point Energy Finance Limited)** 4 England and Wales 100% \u2013 Ithaca SP (Holdings) Limited (formerly Siccar Point Energy (Holdings) Limited)** 4 England and Wales 100% \u2013 Registered office Country of incorporation % equity interest at 31 December 2022 2021 Ithaca SP (E&P) Limited (formerly Siccar Point Energy E&P Limited)** 4 England and Wales 100% \u2013 Ithaca SP (O&G) Limited (formerly Siccar Point Energy UK Limited)** 4 England and Wales 100% \u2013 Ithaca SPE Limited (formerly Siccar Point Energy Limited)** 4 England and Wales 100% \u2013 Ithaca Zeta Limited (formerly Summit Exploration and Production Limited)** 4 England and Wales 100% \u2013 Transactions between subsidiaries are eliminated on consolidation. * The Group acquired 100% of the share capital of Ithaca MA Limited (formerly Marubeni Oil & Gas (UK) Limited) on 4 February 2022. Further details on the acquisition are set out in note 17. ** The Group acquired 100% of the share capital of Ithaca SP Bonds PLC, Ithaca SP Finance Limited, Ithaca SP (Holdings Limited), Ithaca SP (E&P) Limited, Ithaca SP (O&G) Limited, Ithaca SP UK Limited, Ithaca SPE Limited and Ithaca Zeta Limited on 30 June 2022. Further details on the acquisitions are set out in note 17. *** Ithaca SPL Limited was dissolved on 15 February 2022. 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 The following table provides the loan balances with related parties as of 31 December: Borrowings \u2013 principal amount (note 20) 2022 US$\u2019000 2021 US$\u2019000 Subordinated loan due to DKL Energy Limited \u2013 (63,000) Capital Notes issued to DKL Energy Limited \u2013 (374,076) \u2013 (437,076) Amounts due to parent (note 22) 2022 US$\u2019000 2021 US$\u2019000 Delek Group Limited \u2013 (28,941) Subordinated loan due to DKL Energy Limited \u2013 (14,090) Other amounts owed to parent \u2013 (377) \u2013 (43,408) The outstanding interest of $29 million with respect to the 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 (note 20) and subsequent settlement of the $392 million balance under the waiver agreement as detailed below. 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 the Capital Note and subordinated Loan balances (including interest) totalling $469 million, such that, post IPO these balances would no longer be due from Ithaca Energy plc. The following table provides breakdown of amounts settled under the waiver agreement: Status of outstanding loans as of 8 November 2022 Outstanding Balance US$\u2019000 Repayment of loans US$\u2019000 Loan Waiver US$\u2019000 Subordinated loan due to DKL Energy Limited (63,000) 63,000 \u2013 Subordinated loan due to DKL Energy Limited (interest) (14,406) 14,406 \u2013 Capital Notes issued to DKL Energy Limited (392,000) 210,055 (181,945) (469,406) 287,461 (181,945) The loan waiver of $181.9 million was recognised as a Capital Contribution on equity. The following table provides remuneration to key management personnel, being persons having direct or indirect authority or responsibility of the Group, for the periods ended 31 December 2022 and 2021: Key management personnel 2022 US$\u2019000 2021 US$\u2019000 Salaries and short-term employee benefits 4,590 3,136 Payments made in lieu of pension contributions 229 112 Company pension contributions 106 155 Share-based payment 12,623 \u2013 17,548 3,403 Further detail regarding share-based payments received by key management personnel is set out below. ",
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"fact-328": {
"value": "DKL Energy Limited",
"dimensions": {
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"fact-329": {
"value": "Delek Group Limited",
"dimensions": {
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"language": "en",
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"fact-390": {
"value": "33. Share-based payments The charge for share-based payment transactions in the year to 31 December 2022 was $14.1 million (2021: $nil). 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, pre-licence exploration costs or general and administrative costs. 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 9,433,494 Balance at 31 December 2022 1,687,296 4,908,903 2,836,660 9,433,494 Exercisable at 31 December 2022 \u2013 \u2013 \u2013 \u2013 Exercise price $nil $nil $nil N/A Weighted average remaining life 0.9 years 2.9 years 3.3 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 vest over the period to 14 November 2023, the At-IPO awards vest over the period to 14 November 2025 and the 2022 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 2022 was $0.6 million (2021: $nil). IPO-related share options Under the terms section 11.6 of the Prospectus, the Executive Chairman, Gilad Myerson (GM) and the 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 vest equally over the period 21 July 2021 to 20 July 2026. During the year Mr Myerson exercised 1,402,759 share options. The total charge for\u202fIPO-related share options in the year to 31 December 2022 was $7.3 million (2021: $nil). GM options AB options Total Balance at 1 January 2022 \u2013 \u2013 \u2013 Granted during the year 2,337,931 2,337,931 4,675,862 Exercised during the year (1,402,759) \u2013 (1,402,759) Balance at 31 December 2022 935,172 2,337,931 3,273,103 Exercisable at 31 December 2022 935,172 467,586 1,612,852 Exercise price \u00a30.01 \u00a30.01 N/A Weighted average remaining life N/A 2.7 years N/A Management Equity Plan (MEP) During the year 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) described below. These options have the following vesting conditions: Period Percentage vesting B1 B2 to 1 October 2022 0% 0% 1 October 2022 to 30 September 2023 15% 0% 1 October 2023 to 30 September 2024 30% 0% 1 October 2024 to 30 September 2025 45% 45% 1 October 2025 to 30 September 2026 100% 100% Under the terms of the MIA there is a reassessment of the overall value of Ithaca Energy plc at each vesting date and under certain circumstances Mr Myerson could be awarded further B1 and B2 shares which would vest as above. If an exit event (for example a takeover of the Group) occurs on or after 1 October 2024 then the B1 and B2 shares would immediately vest in full. Should Mr Myerson become a bad leaver before the end of the vesting period his entitlement to the shares would be as at the termination date and there would be no further vesting. Under the terms of the SSBA, Mr Myerson is also entitled to an AGP of $10.0 million, less any special bonuses paid since September 2021, if no exit is completed before 1 October 2023. The payment is in lieu of all MEP shares which must be transferred back to the Company for nil payment. The payment is intended to operate as a floor on the value that Mr Myerson may receive in recognition of his contribution to value creation from 2019 onwards and the incentive arrangements forfeited by him on commencement of employment with the Group. Entitlement to the AGP accrues evenly over the period 1 September 2021 to 30 September 2023 and is payable 1 December 2023. There are 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 2022 was $6.2 million (2021: $nil). As it is anticipated that this will be cash-settled within 12 months of the balance sheet date, this element has been treated as a current liability at 31 December 2022 and is included within accruals. The share-based payment reserve of $4.9 million reflects the charge of $0.6 million for LTIPs plus the charge of $7.3 million for IPO-related share options less the cost of exercises during the year of $3.0 million. ",
"dimensions": {
"concept": "ifrs-full:DisclosureOfSharebasedPaymentArrangementsExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
},
"fact-391": {
"value": "34. Subsequent events 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 Ithaca will receive approximately $51 million which will be reflected in the 2023 financial statements, with no amounts having been previously recognised in the financial statements. An interim dividend of $133 million, or $0.1321 per share was declared after the end of the year and was paid to shareholders on 9 March 2023.",
"dimensions": {
"concept": "ifrs-full:DisclosureOfEventsAfterReportingPeriodExplanatory",
"language": "en",
"entity": "scheme:21380057TNFLXPXBIP34",
"period": "2022-01-01T00:00:00/2023-01-01T00:00:00"
}
}
}
}