Full Year 2022 Results

RNS Number : 7518U

Ithaca Energy PLC

30 March 2023

 

Press release

30 March 2023

Ithaca Energy plc ("Ithaca Energy" or the "Group")

Full Year 2022 Results

 Transformational year for Ithaca Energy, positioning the Group for long-term value creation
Ithaca Energy plc today announces its audited full year results for the year ended 31 December 2022. 
Key financial performance indicators (KPIs)

2022 2021 Group adjusted EBITDAX1($m) 1,916.2 1,035.4 Net cash flow from operating activities ($m) 1,723.3 912.7 Available liquidity1($m) 578.8 619.8 Total production (boe/d) 71,403 56,486 Unit operating expenditure1($/boe) 19.0 18.0 Basic EPS (cents) 102.6 42.4 Net debt1($m) 971.2 930.2 Net debt/Group adjusted EBITDAX1 0.5x 0.9x

Other KPIs

Tier 1 process safety events	-	-
Serious injury and fatality frequency	-	-
Scope 1 and 2 emissions (tCO 2 e3)	483,325	497,929
Green house gas intensity (kgCO 2 e/boe)	23.8	24.6

¹ Non-GAAP measure (see pages 75 to 77)

Corporate Highlights

·   Successfully listed on the premium segment of the main market of the London Stock Exchange on 14 November 2022, and subsequently joined the FTSE 250 index in March 2023

·   Transformational $1.1 billion acquisition of Siccar Point Energy (Holdings) Limited ("Siccar Point Energy") completed on 30 June 2022, doubling the Group's recoverable resources

·   Acquisitions of Summit Exploration and Production Limited ("Summit") and Marubeni Oil and Gas UK Limited ("Marubeni") completed in the first half of the year

·   Ithaca Energy now ranks as the second largest UKCS oil and gas independent by reserves and resources, with year-end 2P reserves of 228 mmboe and 2C resources of 284 mmboe

·   Payment of interim 2023 dividend of $133 million made in March 2023, with targeted total dividend of $400 million for financial year 2023

Operational Highlights

·   The Group achieved record production of 71.4 kboe/d in 2022, a 26% increase from the previous year (2021: 56.5 kboe/d), with a balanced split between liquids (66%) and gas (34%)

·   Continued cost discipline with unit operating expenditure of $19.0/boe in 2022 (2021: $18.0/boe) despite inflationary headwinds

·   Significant development activity at the pioneering Captain Enhanced Oil Recovery ("EOR") Phase II project, with the execution of a large proportion of the offshore work scope

· First oil achieved from the Abigail subsea tieback to the FPF-1 floating production unit in the Greater Stella Area on 20 October 2022, only ten months after development consent

· Successful drilling campaigns at Jade and Mariner and well work completed at Erskine and Alba

· Ongoing maturation of development projects in preparation for final investment decisions

· Clear focus on decarbonisation with Board endorsed emissions reduction strategy which includes achieving Net Zero by 2040, on a Scope 1 & 2 net equity basis, 10 years ahead of NSTD commitments

2022 Financial Highlights

· Strong Q4 2022 financial performance, reporting production rates ahead of expectations and both opex and capex in line with guidance provided at IPO

· Adjusted EBITDAX of $1,916.2 million, an increase of 85.1% (2021: $1,035.4 million), principally driven by revenue growth due to acquisitions made during the year, increased production efficiency and higher realised commodity prices

· Profit before tax of $2,240.5 million (2021: $763.1 million) and adjusted net income after tax of

$462.8 million (2021: $415.5 million) after excluding exceptional non-cash bargain purchase credits of $1,335.2 million and exceptional non-cash Energy Profit Levy deferred tax charges of $766.5 million

· Free cash flow of $1,135 million (2021: $550.5 million)

· Net debt of $971.2 million at year-end (2021: 930.2 million), reducing the Group's leverage position to 0.5x net debt to adjusted EBITDAX (2021: 0.9x) despite material M&A activity in the year

Outlook for 2023

· Average production in Q1 2023 of 70-72 kboe/d primarily due to delayed start up of the non- operated Pierce field, deferred volumes on Abigail (highlighted at IPO) and operational issues at Captain (resolved during March)

· Full year 2023 production guidance revised to 68-74 kboe/d, previously 72-80 kboe/d, reflecting lower Q1 volumes, non-operated portfolio delivery and the impact of the Energy Profit Levy to capital programmes

· Reduction in net opex guidance to $560 million - $630 million, previously $590 million - $680 million, reflecting continued cost discipline and lower estimated fuel and diesel costs

· Reduction in net producing asset capex guidance to $400 million - $460 million, from $450 million -

$550 million, (excluding capital investment for projects awaiting final investment decision) reflecting deferral of activity to 2024, reduction in scheduled activity following the introduction of the Energy Profit Levy and optimisation of our capital programme

· Revisions in management guidance across production, opex and capex are expected to have limited cash impact at current commodity prices based on mid-point guidance changes

· Material ongoing project activity at Captain EOR phase II including the drilling of further wells, installation of the required flowlines and umbilicals, and completion of the topside construction and commissioning

· Continued focus on emissions reduction initiatives including commencement of FEED activity to explore the potential for electrification at our flagship Captain asset

· Exploration drilling of high potential K2 target scheduled to commence in summer

· Near-term final investment decisions across our greenfield and brownfield development portfolio, with the focus on prioritising the allocation of capital to maximise sustainable shareholder returns

· Payment of interim 2023 dividend of $133 million made in March 2023, with targeted total dividend of $400 million for financial year 2023

Gilad Myerson, Executive Chairman, commented: "2022 has been a transformational year for Ithaca Energy, evidenced by material M&A activity, including the landmark acquisition of Siccar Point Energy, adding both scale and longevity to our existing portfolio. We have executed against our strategy, to buy, build, and boost assets, with the year culminating in the Group's IPO on the London Stock Exchange in November 2022, and subsequent inclusion in the FTSE 250 index in March 2023.

Ithaca Energy has a sizeable portfolio of cash generative assets together with a strong pipeline of development opportunities that support an attractive growth trajectory. Our core focus in 2023, will be on prioritising investment across our current high-value portfolio to maximise sustainable shareholder returns.

The UK oil and gas industry experienced significant fiscal instability with the introduction and subsequent revision of the Energy Profit Levy in 2022. In its revised form, the Energy Profit Levy, and the fiscal uncertainty it has created, brings material and negative unintended consequences for financing capacity, JV partner alignment, and the free cash flow generation required to support continued investment. We continue to look towards the UK government to create an economic environment that encourages investment in the UK North Sea."

Alan Bruce, Chief Executive Officer , commented: "I believe we can look back on 2022 with a great deal of satisfaction. It was a year in which we completed three significant transactions while also delivering organic growth, cementing Ithaca Energy's position as one of the leading independent exploration and production companies operating in the UK North Sea. We continued to demonstrate our ability to deliver projects, safely and responsibly, while defining an emissions reduction roadmap that reflects our ambition to have one of the lowest carbon portfolios in the UK Continental Shelf.

Our people have always been the key to our success, and I'd like to recognise and thank both our offshore and onshore teams for their hard work and tireless dedication. We also welcome our new Board members who bring unrivalled sector knowledge and a valuable blend of complementary skills to the Group."

Ithaca Energy will host an in person and virtual presentation and Q&A session for investors and analysts at 09:00 (BST) today, 30 March 2023, accessible via our website: https://investors.ithacaenergy.com/.

2022 in review

Delivering material scale and portfolio longevity in 2022

With three acquisitions completed in 2022, including the transformative acquisition of Siccar Point Energy, we continued to build our track record of delivering material value creation, and positioned Ithaca Energy as a substantial North Sea enterprise, with a portfolio of significant scale and longevity. Our impressive growth story, delivered through both organic growth and value-accretive M&A activity, supported the Group's successful admission to the premium segment of the London Stock Exchange in November 2022.

In scale, we now rank as the second largest independent in the UK Continental Shelf ("UKCS") by resources and third largest by production. Our diverse portfolio includes interests in six of the top ten assets by reserves in the UKCS, more than any other player, including significant stakes in two of the three largest undeveloped discoveries in the UKCS, Cambo and Rosebank.

In 2022, we increased our 2P Proven and Probable reserves to 228 mmboe at 31 December 2022 (2021: 184 mmboe). The addition of Siccar Point Energy's portfolio materially enhanced our portfolio longevity with a highly competitive reserves-to-production ratio of 19 years, among the highest in the UKCS.

Production growth driven by acquisitions

Our production in 2022 rose to an average of 71.4 kboe/d (2021: 56.5 kboe/d). In the first half of the year production averaged 66.7 kboe/d, increasing to 76.1 kboe/d in the second half of the year reflecting material producing asset additions following the completion of M&A transactions in the year, including the acquisition of Marubeni in Q1 2022 and both Summit and Siccar Point Energy in Q2 2022.

In Q4 2022, strong operational performance resulted in average production of 80.8 kboe/d, delivering ahead of management guidance of 77-80 kboe/d.

Operating costs in 2022 of $496.0 million, representing a net unit opex cost of $19.0 /boe (2021: $18.0/boe), increased from 2021 ($371.1 million) substantially driven by higher cost of fuel gas and diesel. Q4 2022 net opex of $136.7 million, was toward the lower end of management guidance of $130 - $150 million.

Total net capital expenditure (excluding decommissioning) in 2022 of $405 million (2021: $388 million), reflected investment activity across our asset base including the Captain EOR Phase II development; Abigail subsea-tieback development, well-work at Erskine and Alba; appraisal drilling at Isabella; and a successful development drilling campaign at Jade. Q4 2022 net capex (excluding decommissioning) of $105 million was in-line with management guidance of $100 - $120 million.

Operational excellence, starting with safety

Safety is our non-negotiable, number-one priority and is central to our business success. We empower our people to be Safety Leaders, with the right and responsibility to act in line with our Stop Work Authority and always adhering to the Life Saving Rules.

During 2022, our serious incident and fatalities record remained at zero, as it has since 2019. There were no Tier 1 and two Tier 2 process safety events during the year. We saw an increase in occupational safety events as activity levels increased resulting in an expanded and less experienced workforce across the industry. Further, onsite management engagement has been more challenging during the COVID-19 pandemic, and so our focus has been on reducing the administrative burden faced by work-site leaders to provide more time for field verification of safety critical tasks.

Development expertise and growth pipeline

Our expertise extends across the full life cycle of E&P operations. In 2022, we have grown our reserves base organically, through investment programmes focused on production enhancement, satellite field developments, and exploration and appraisal activities.

Our development expertise came to the fore in 2022, with large programmes focused around our infrastructure hubs including the subsea tie-in of the Abigail field to FPF-1, just 10 months after final development consent. We made material progress during the year on Phase II of our pioneering polymer enhanced oil recovery development programme, to maximise recovery rates from the Captain field. We have executed a significant proportion of the project's offshore work scope including the installation of the process modules, pipework, B28 flow line and riser caisson, drilling and completion of first stage II well UB05P. In September 2022, Captain Enhanced Oil Recovery Phase l reached a significant milestone of 10 million barrels of oil production through the polymer flood enhanced oil recovery method.

Our production performance in 2022 has been supported by strong production efficiency performance, reflecting our commitment to maximise asset value through operational excellence. Most notably at FPF-1, where our focus on value and our willingness to invest to drive operational efficiency and uptime improvements, has resulted in a significant increase in production efficiency in 2022 to above 90%, from an average of 60% in 2021. Across our portfolio, we have launched digitalisation initiatives to ensure safe and efficient operations, delivering increased uptime and cost savings.

In response to the North Sea Transition Authority call for applications in the UKCS 33rd Offshore Oil and Gas Licensing Round, we drew on our in-house exploration and appraisal expertise to apply ahead of the closing date on 12 January 2023. Targeting adjacent upside potential to existing infrastructure and greenfield developments, we submitted nine applications, five as proposed operator of the licence. We expect the first licences will be awarded from Q2 2023.

Decarbonisation focus with a well-defined emissions-reduction strategy

We made significant progress in sharpening our decarbonisation focus in 2022. We formalised our plans to significantly reduce emissions and exceed industry targets by optimising our current portfolio in the short- term, and fundamentally transitioning the portfolio in the medium to long-term.

We acknowledge that the energy transition is a fundamental challenge to our industry and the targets we have set for decarbonisation are difficult to achieve. Our well-defined roadmap of emission reduction initiatives supports an ambitious goal to achieve a 25% reduction in Scope 1 and 2 CO2 and CO2e emissions from our operated assets by 2025 (against a 2019 baseline). Our medium-term target is to shift from higher to lower-emission intensity assets. As assets such as FPF-1 and Alba come to the natural end of their life, they will be replaced by lower-intensity fields such as Rosebank and Cambo. In parallel, we are evaluating technologies which could materially reduce emissions at Captain. In the long-term, we are committed to supporting the North Sea Transition Deal ("NSTD") and intend to achieve Net Zero by 2040 (on a Scope 1 and 2 net equity basis), ten years ahead of current NSTD commitments.

Focus on maximising shareholder value

As we embark on our journey as a publicly listed company, we have established a robust and balanced capital allocation framework that will support our ambition to deliver continued growth while providing attractive shareholder returns.

We expect that, subject to no material downward pressure on oil and gas prices and a stable fiscal regime, our cash flow generation will satisfy capital expenditure requirements to sustain current production levels of between 70-90 kboed/d; maintain a leverage position below 1.5x net debt to adjusted EBITDAX; deliver shareholder returns; and provide additional financial flexibility to facilitate further value-accretive growth opportunities.

During 2022, our diversified, high-quality asset base generated free cash flow of $1,135 million. This strong cash flow generation supported a rapid deleveraging trajectory, with the Group reporting net debt of $971.2 million, representing a net debt to adjusted EBITDA ratio of 0.5x at the year-end.

Achieving this deleveraging in a year when we completed over $1 billion of transactions, and deployed capital of $405 million to deliver continued organic growth, reflects both the strength of our portfolio and our ambitions for further growth.

With a balanced capital allocation policy, through the cycle dividend target of 15-30% of post-tax cash flow from operations, and proven track record of material value creation, we believe Ithaca Energy represents an attractive investment opportunity with significant potential for growth.

Outlook for 2023 and beyond

We enter 2023 as a public company, with greater scale, diversification, reserves and leadership expertise, better positioned than ever to deliver growth.

With a diverse, high-value portfolio of producing assets and significant brownfield and greenfield development opportunities such as Rosebank, Cambo, Marigold, Fotla, and Tornado and infill drilling at Captain, Alba, Montrose, Schiehallion and Mariner we have considerable investment optionality across our portfolio. Our focus during the year will be on prioritising investment across our current portfolio to maximise shareholder returns.

We will maintain a watching brief on value-accretive acquisition opportunities taking a selective and disciplined approach, as we manage our capital allocation priorities in line with our stated capital allocation framework.

As a result of lower than estimated production in Q1 2023, primarily due to delayed start-up of the non- operated Pierce field, lower than forecasted volumes from Abigail and operational issues at Captain (that have subsequently been resolved), and the impact of the Energy Profit Levy to 2023 capital programmes we provide updated 2023 production guidance of 68-74 kboe/d (revised from 72-80 kboe/d).

We continue to have a strong focus on costs and provide updated net opex guidance of $560 million - $630 million (reduced from $590 million - $680 million). Updated guidance reflects a modest rise in our average opex per barrel from 2022, due to current inflationary pressures and increased fuel and diesel costs. Our mid- term ambition is to drive down our average operating cost per barrel as we transition our portfolio to earlier- life assets with lower operating costs.

As a result of a reduction in scheduled activity across our non-operated portfolio, as a result of the introduction of the Energy Profit Levy, and deferral of activity from 2023 to 2024 we provide updated 2023 net capex guidance of $400 million - $460 million (excluding capital investment for projects awaiting final investment decision), a reduction from previous guidance of $450 million - $550 million.

Revisions in management guidance across production, opex and capex are expected to have limited cash impact at current commodity prices based on mid-point guidance changes. The Group is recommitting to its dividend target of 15-30% of post-tax cash flow from operations and its targeted 2023 dividend of $400 million, as communicated at the time of IPO.

We remain committed to investing in the UK North Sea, however the impact of the revised Energy Profit Levy ("EPL") announced in November 2022, in particular the removal of the sunset clause, is constraining our ability, and that of our JV partners, to invest. With a reduction in borrowing capacity across the sector as a direct result of EPL, the ability of the oil and gas industry to unlock the benefits of investment programmes across the UKCS to provide critical domestic energy security and meet its Net Zero ambitions is under threat. We continue to constructively engage with the UK government in relation to the future fiscal policy in pursuit of the stability required to make these critical investment decisions.

Enquiries

Ithaca Energy
Kathryn Reid - Head of Investor Relations, Corporate Affairs & Communications	[e-mail]
FTI Consulting (PR Advisers to Ithaca Energy)	[phone]
Ben Brewerton / Nick Hennis	[e-mail]

About Ithaca Energy plc

Ithaca Energy is a leading UK independent exploration and production company focused on the UK North Sea with a strong track record of material value creation. In recent years, the Company has been focused on growing its portfolio of assets through both organic investment programmes and acquisitions and has seen a period of significant M&A driven growth centred upon two transformational acquisitions in recent years. Today, Ithaca Energy is one of the largest independent oil and gas companies in the United Kingdom Continental Shelf (the "UKCS"), ranking second by resources.

With stakes in six of the ten largest fields in the UKCS and two of UKCS's largest pre-development fields, and with energy security currently being a key focus of the UK Government, the Group believes it can utilise its significant reserves and operational capabilities to play a key role in delivering security of domestic energy supply from the UKCS.

Ithaca Energy serves today's needs for domestic energy through operating sustainably. The Group achieves this by harnessing Ithaca Energy's deep operational expertise and innovative minds to collectively challenge the norm, continually seeking better ways to meet evolving demands.

Ithaca Energy's commitment to delivering attractive and sustainable returns is supported by a well-defined emissions-reduction strategy with a target of achieving net zero by 2040.

Ithaca Energy plc was admitted to trading on the London Stock Exchange (LON: ITH) on 14 November 2022.

Finance Review

AN ASSET PORTFOLIO GENERATING STRONG OPERATIONAL CASH FLOWS AND EARNINGS

· Group adjusted EBITDAX $1,916.2m (2021: $1,035.4m)

· Net cash flow from operating activities $1,723.3m (2021: $912.7m)

· Statutory net income $1,031.5m (2021: $426.0m)

· Adjusted net income $462.8m (2021: $415.5m)

· Leverage ratio - net debt to Group adjusted EBITDAX 0.5x (2021: 0.9x)

· Statutory earnings per share 102.6 cents (2021: 42.4 cents)

Transformational growth whilst maintaining financial discipline has been the story of 2022. We have reduced leverage to 0.5x net debt to adjusted EBITDAX whilst materially increasing production, maintaining operating cost discipline and adding quality reserves and resources. Our asset portfolio has been strengthened by the addition of further long-lived asset equity positions with low operating costs delivering strong adjusted EBITDAX growth (up 85.1% on 2021) and free cash flow growth (up 106.1% on 2021), as well as the addition of material large project equity positions offering access to future growth opportunities. As we move forward, our financial commitment to investors is to deliver value through a transparent capital allocation framework that guides our corporate decision making. Through the framework we commit to allocate cash flow in a prioritised order to:

1. INVEST- to sustain production in the 70-90kboe/d range in the medium term

2. PROTECT- to maintain prudent leverage ratios (<1.5x) and reduce exposure to commodity price downturns through an active hedging strategy

3. RETURN- to share the results of operational performance with investors by delivering 15-30% post tax CFFO in dividends annually

4. EVOLVE- to deploy residual free cash flow to grow our assets organically, extend the business through M&A or yield additional distributions to investors

The introduction of the Energy Profits Levy (EPL) is extremely disappointing for the industry as it reduces the free cash flow available for reinvestment. However, despite this we have created significant organic and inorganic value through 2022 and we believe our capital allocation framework should give investors confidence as we seek to continue to grow value through 2023, and beyond.

The Group reported average production of 71,403 boe/d for 2022 (2021: 56,486 boe/d) driving Group adjusted EBITDAX of $1,916.2 million, net cash from operations of $1,723.3 million and net income of $1,031.5 million. Comparing the financial results for 2022 with 2021 demonstrates the transformational nature of 2022 and the direct impact of The Group's buy, build, boost strategy.

Financial performance: adjusted EBITDAX

Adjusted EBITDAX is a key measure of operational performance delivery in the business and increased by 85.1% in 2022 to $1,916.2 million (2021: $1,035.4 million) mainly driven by revenue growth of $1,170.3 million to $2,598.5 million (2021: $1,428.2 million). Revenue growth was principally due to acquisitions made during the year which contributed an additional $552 million of revenue, improved production efficiency as well as higher commodity prices year-on-year.

Increased production was delivered from new field equity production from acquisitions including from the MonArb area fields (from February 2022), and from Jade, Elgin Franklin, Mariner and Schiehallion fields (from July 2022).

Substantial price volatility was experienced through 2022, with historically exceptional movements in the European gas markets and continued volatility in the international oil markets. Ithaca Energy's value constructive hedging policy enabled substantial participation in price upside through the year whilst protecting downside risk. Average realised oil prices for the year were $100/boe before hedging results and $91/boe after hedging results (2021: $69/boe before hedging results and

$66/boe after hedging results). Average realised gas prices for the year were $149/boe before hedging results and $137/boe after hedging results (2021: $96/boe before hedging results and

$77/boe after hedging results).

Cost discipline was maintained during the year with unit operating expenditure marginally increasing to $19.0/boe (2021: $18.0/boe) as inflationary pressures and higher commodity price based operating costs, such as fuel gas and diesel, outweighed our disciplined cost management approach across the portfolio.

Revenue, opex and adjusted EBITDAX are as follows:

Production (boe/d)	2022 71,403 $m	2021 56,486 $m
Oil sales	1,692.7	856.5
Gas sales	1,348.2	724.5
NGL sales	75.4	52.5
Other income	40.6	32.7
Realised losses on oil derivative contracts	(211.6)	(48.8)
Put premiums on oil derivative instruments	(14.6)	(27.2)
Realised losses on gas derivative contracts	(289.9)	(147.4)
Put premiums on gas derivative instruments	(42.3)	(14.6)
Total revenue	2,598.5	1,428.2
Operating costs	(547.8)	(424.0)
Inventory movements, administration expenses and other items	(134.5)	31.2
Adjusted EBITDAX	1,916.2	1,035.4

Financial performance: net Income

	2022	2021
Profit before tax ($m)	2,240.5	763.1
Tax ($m)	(1,209.0)	(337.1)
Net income after tax ($m)	1,031.5	426.0
Gain on bargain purchase ($m)	(1,335.2)	(10.5)
EPL deferred tax charge ($m)	766.5	-
Adjusted net income1($m)	462.8	415.5
Earnings per share (Cents)	102.6	42.4
Adjusted earnings per share1(Cents)	46.0	41.3

¹ Non-GAAP measure

Net income in 2022 represented significant value delivery with $1,031.5 million of profit compared with $426.0 million in 2021. Net income was substantially impacted by bargain purchase gains on acquisitions of $1,335.2 million and exceptional deferred tax charges associated with the introduction of the EPL, of $766.5 million during the year.

Total costs

Total costs amounted to $358.0 million (2021: $665.1 million) and comprised:

	2022 $m	2021 $m
Depletion, depreciation and amortisation	(662.9)	(455.9)
Operating costs	(547.8)	(424.0)
Movements in oil and gas inventory	(130.3)	7.0
Royalties	(11.3)	(6.2)
Impairment (charges)/reversals	(31.5)	465.3
Exploration and evaluation expenses	(9.0)	(0.2)
Other (losses)/gains	(9.5)	3.7
Administrative expenses	(87.9)	(15.2)
Gain on bargain purchase	1,335.2	10.5
Net finance costs ($m)	(203.0)	(250.1)
Total costs	(358.0)	(665.1)

Depletion, depreciation and amortisation charges were $662.9 million (2021: $455.9 million). The year-on-year increase is principally due to the acquisitions made during the year. Depletion, depreciation and amortisation per barrel was $25 (2021: $21).

Operating costs amounted to $547.8 million (2021: $424.0 million) wit the increase driven mainly by the acquisitions made during the year. As set out above unit operating expenditure marginally increased year-on-year.

Movements in oil and gas inventory was a charge of $130.3 million (2021: credit of $7.0 million) representing movements in underlift/overlift entitlement imbalances.

Impairment charges of $31.5 million (2021: reversal of $465.3 million) principally reflect revisions to asset retirement obligations, primarily on fields that are no longer producing.

Exploration and evaluation costs amounted to $9.0 million (2021: $0.2 million) and principally related to licence relinquishments during the year.

Other losses of $9.5 million (2021: gains of $3.7 million) comprise fair value losses on contingent consideration and adverse foreign exchange movements.

Administrative expenses were $87.9 million (2021: $15.2 million) with the increase principally due to non-recurring costs associated with the IPO of $20.3 million, acquisition costs of $25.8 million and share-based payment charges of $14.1 million relating to new share option awards.

Gain on bargain purchase arose on the Marubeni and Siccar Point Energy acquisitions (see note 17 for further details).

Net finance costs were $203.0 million (2021: $250.1 million) with the reduction principally due to lower interest on related party loans which were repaid during the year and lower loan fee amortisation.

Taxation

The tax charge for the year was $1,209.0 million (2021: $337.1 million) including an exceptional EPL deferred tax charge of $766.5 million and a current EPL tax charge of $131.4 million.

Earnings per share

Earnings per share of 102.6 cents (2021: 42.4 cents) and when adjusted for exceptional items (after excluding an exceptional non-cash bargain purchase credit of $1,335.2 million and exceptional non- cash deferred tax charges of $766.5 million) was 46.0 cents (2021: 41.3 cents).

Dividends

The Board did not propose a dividend for 2022 but reaffirmed the target of a $400 million for 2023 financial year. An interim dividend of $133 million, or $0.1321 per share, was paid to shareholders on 9 March 2023.

Financial position: assets/liabilities/equity

	2022	2021
	$m	$m
Total assets	6,759.6	4,731.8
Total liabilities	(4,302.1)	(4,055.3)
Net assets and shareholders' equity	2,457.5	676.5

Assets

At 31 December 2022, total assets amounted to $6,759.6 million (2021: $4,731.8 million), of which current assets were $988.7 million (2021: $560.9 million) and non-currents assets were $5,770.9 million (2021: $4,170.9 million). The increase in total assets during the year was primarily due to organic capital investment, recognition of oil and gas assets from acquisitions accounted for as business combinations under IFRS 3 which added $1,115.0 million to development and production assets and $706.6 million to exploration and evaluation asset. In addition there were increases in the valuation of commodity derivative contract assets.

Liabilities

At 31 December 2022, total liabilities amounted to $4,302.1 million (2021: $4,055.3 million) including decommissioning provisions of $1,720.5 million (2021: $1,641.5 million) and borrowings of

$1,213.7 million (2021: $1,391.7 million). The increase in total liabilities during the year was primarily due to additional decommissioning liabilities of $390.5 million and contingent and deferred consideration of $286.8 million from the acquisitions made during the year, partly offset by reduced borrowings due to settlement of the parent debt position and lower commodity derivative contract liabilities.

Equity and reserves

At 31 December 2022, total equity and reserves amounted to $2,457.5 million (2021: $676.5 million). The increase in equity and reserves during the year was primarily due to the retained profit for the year, IPO related capital movements and favourable hedging reserve movements.

Financial position: cash

	2022	2021
	$m	$m
Opening cash	44.8	1.2
Operating cash flows	1,723.3	912.7
Investing cash flows	(1,404.2)	(220.2)
Financing cash flows	(107.4)	(650.7)
Foreign exchange	(2.7)	1.8
Net cash flow	209.0	43.6
Closing cash	253.8	44.8
Undrawn borrowing facilities	325.0	575.0
Available liquidity	578.8	619.8

Operating cash flows

Net cash from operating activities amounted to $1,723.3 million (2021: $912.7 million) after accounting for working capital movements of $94.8 million (2021: $74.2 million) with the increase being driven by higher production and prices partly offset by higher operating costs.

Investing cash flows

Cash flow used in investing activities amounted to $1,404.2 million (2021: $220.2 million) reflecting increased capital expenditure of $380.6 million (2021: $269.6 million) driven mainly by the Captain and Abigail development projects as well as investing cash flows relating to acquisitions (net of cash acquired) of $957.4 million being primarily driven by the Siccar Point Energy ($926.7 million) acquisition.

Financing cash flows

Cash outflow from financing activities of $107.4 million (2021: $650.7 million) with increased interest costs and lease payments of $177.2 million (2021: $88.7 million) and a net increase in principal debt of $50.0 million (2021: reduction of $554.8 million). In line with the IPO Prospectus, there were no substantive net cash flows as a result of the IPO with IPO proceeds used to repay a shareholder loan.

Cash balances were $253.8 million (2021: $44.8 million) at the end of the year and available liquidity was $578.8 million (2021: $619.8 million).

Derivative financial instruments

Derivative financial instruments are utilised to manage commodity price risk in a substantive financial hedging programme for future oil and gas production volumes. As at 31 December 2022, the following hedges were in place:

Oil	2023	2024
Volume hedged (mmboe)	7.6	0.4
Average hedged price ($/bbl)	68	77
Gas
Volume hedged (mmboe)	3.4	0.3
Average hedged price ($/bbl)	220	175

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 the Group will receive approximately $51 million which will be reflected in the 2023 financial statements.

Principal risks

The principal risks facing the Group are set out in part 2 of the IPO Prospectus.

Going concern

Management closely monitor the funding position of the Group including monitoring continued compliancewithcovenantsandavailablefacilitiestoensuresufficientheadroomismaintainedtofund operations. Management have considered a number of risks applicable to the Group that may have an impact on the Group's ability to continue as a going concern. Short-term and long-term cash forecasts are produced on a weekly and quarterly/annual basis respectively along with any related sensitivity analysis. This allows proactive management of any business risks 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:

• Strong commodity markets in 2022, continuing robust commodity price backdrop despite lower prices in March 2023 and a well hedged portfolio over the next 12 months:

• Reserves Based Lending headroom of $475 million ($450 million drawn versus

$925 million available), plus $210 million of cash at 24 March 2023; and

• Strong operational performance and well diversified portfolio which has been further strengthenedbytheacquisitionsofSiccarPointEnergyandSummitasat30June2022andwith Abigail coming online in November 2022.

The Group's base case going concern assessment assumes an average oil price of $77/bbl and a gas price of 119p/therm in 2023 and an oil price of $72/bbl and a gas price of 130p/therm in the six months to 30 June 2024 with production in line with approved asset plans.

Owing to 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 meets its liabilities as they fall due in the context of the mitigation strategies available to management. 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 price 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 cancellationordeferraloffuturedividendsandfurtherpotentialtorefinancetheGroup's borrowing arrangements.

Based on their assessment of the Group's financial position over the period to 30 June 2024, The Directors believe that the Group will be able to continue in operational existence for the foreseeablefuture.Accordingly, theycontinuetoadoptthe goingconcernbasisofaccountingin preparing the consolidated financial statements.

Basis of preparation

The financial information for the year ended 31 December 2022 does not constitute statutory accounts as defined by sections 435 (1) and (2) of the Companies Act 2006 but is derived from those accounts. The auditor has reported on these accounts; their report was unqualified. Their report did not include reference to any matters to which the auditor drew attention by way of emphasis of matter and did not contain a statement under sections 498 (2) or (3) of the Companies Act 2006.

While the financial information included in this announcement has been prepared in accordance with the recognition and measurement criteria of United Kingdom adopted International Accounting Standards, this announcement does not in itself contain sufficient information to comply with those standards.

CONSOLIDATED STATEMENT OF PROFIT OR LOSS FOR THE YEAR ENDED 31 DECEMBER
		2022	2021
	Note	US$'000	US$'000
Revenue	5	2,598,482	1,428,240
Cost of sales	6	(1,352,324)	(879,181)
Gross profit		1,246,158	549,059
Impairment (charge)/reversal	19	(31,467)	465,271
Exploration and evaluation expenses	14	(9,040)	(156)
Administrative expenses	7	(87,851)	(15,180)
Other (losses)/gains	8	(9,429)	3,827
Gain on bargain purchase	17	1,335,171	10,454
Profit from operations before tax and net finance costs		2,443,542	1,013,275
Net finance costs	9	(203,013)	(250,136)
Profit before tax		2,240,529	763,139
Income tax	27	(1,208,997)	(337,150)
Profit attributable to owners of the parent		1,031,532	425,989
Earnings per share for profit attributable to the ordinary equity holders of the Company	Note	2022 Cents	2021 Cents
Basic earnings per share	10	102.6	42.4
Diluted earnings per share	10	102.2	42.3

The results above are entirely derived from continuing operations.

The accompanying notes on pages 22 to 74 are an integral part of the financial statements.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME FOR THE YEAR ENDED 31 DECEMBER
	Note	2022 US$'000	2021 US$'000
Profit for the year		1,031,532	425,989
Items that may be reclassified to profit and loss
Fair value gain/(loss) on cash flow hedges and cost of hedging	29	468,093	(486,579)
Deferred tax (charge)/credit on cash flow hedges and cost of hedging	27	(200,455)	194,632
Other comprehensive profit/(loss)		267,638	(291,947)
Total comprehensive profit attributable to owners of the parent		1,299,170	134,042
The accompanying notes on pages 22 to 74 are an integral part of the financial statements.

CONSOLIDATED STATEMENT OF FINANCIAL POSITION AS AT 31 DECEMBER
	Note	2022 US$'000	2021 US$'000
Assets
Current assets
Cash and cash equivalents		253,822	44,849
Trade and other receivables	11	359,994	228,290
Decommissioning receivable	11	38,115	94,640
Prepaid expenses and decommissioning securities	12	9,055	10,536
Inventories	13	176,881	177,619
Derivative financial instruments	30	150,858	4,975
		988,725	560,909
Non-current assets
Decommissioning receivable	11	162,710	152,184
Long-term inventories	13	-	532
Exploration and evaluation assets	14	775,773	116,355
Property, plant and equipment	15	3,634,896	2,958,733
Deferred tax assets	27	392,456	220,918
Derivative financial instruments	30	21,191	133
Goodwill	18	783,848	722,075
		5,770,874	4,170,930
Total assets		6,759,599	4,731,839
Liabilities and equity
Current liabilities
Borrowings	20	-	(437,076)
Trade and other payables	22	(711,412)	(484,268)
Current tax payable	27	(106,678)	-
Decommissioning liabilities	23	(146,829)	(94,640)
Lease liability	24	(41,637)	(3,211)
Contingent and deferred consideration	25	(107,680)	(49,806)
Derivative financial instruments	30	(136,668)	(438,006)
		(1,250,904)	(1,507,007)

 

	Note	2022 US$'000	2021 US$'000
Non-current liabilities
Borrowings	20	(1,213,731)	(954,616)
Decommissioning liabilities	23	(1,573,711)	(1,546,849)
Lease liability	24	(17,221)	(278)
Contingent and deferred consideration	25	(219,120)	(25,284)
Derivative financial instruments	30	(27,440)	(21,296)
		(3,051,223)	(2,548,323)
Total liabilities		(4,302,127)	(4,055,330)
Net assets		2,457,472	676,509
Shareholders' equity
Share capital	26	11,445	1
Share premium	26	293,712	634,658
Capital contribution reserve	26	181,945	114,000
Share-based payment reserve	26	4,920	-
Cash flow hedge reserve	29	16,710	(242,791)
Cost of hedging reserve	29	3,275	(4,862)
Retained earnings		1,945,465	175,503
Total equity		2,457,472	676,509
The accompanying notes on pages 22 to 74 are an integral part of the financial statements.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEAR ENDED 31 DECEMBER

		Share capital	Share premium	Capital contribution reserve	Share-based payment reserve	Cash flow hedge reserve	Cost of hedging reserve	Retained earnings/ (accumulated losses)	Total
	Note	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Balance at 1 January 2021		1	634,658	114,000	-	4,416	39,878	(250,486)	542,467
Profit for the year		-	-	-	-	-	-	425,989	425,989
Other comprehensive expense		-	-	-	-	(247,207)	(44,740)	-	(291,947)
Total comprehensive (expense)/income for the year		-	-	-	-	(247,207)	(44,740)	425,989	134,042
Balance at 31 December 2021		1	634,658	114,000	-	(242,791)	(4,862)	175,503	676,509
Balance at 1 January 2022		1	634,658	114,000	-	(242,791)	(4,862)	175,503	676,509
Issuance of shares for capital reduction	26	114,000	-	(114,000)	-	-	-	-	-
Reduction in capital	26	(114,000)	(634,658)	-	-	-	-	748,658	-
Issuance of shares	26	11,444	293,712	-	(3,004)	-	-	(10,228)	291,924
Capital contribution through debt cancellation	26	-	-	181,945	-	-	-	-	181,945
Share-based payment charge	33	-	-	-	7,924	-	-	-	7,924
Total comprehensive income for the year:
Profit for the year		-	-	-	-	-	-	1,031,532	1,031,532
Other comprehensive income		-	-	-	-	259,501	8,137	-	267,638
Total comprehensive income for the year		-	-	-	-	259,501	8,137	1,031,532	1,299,170
Balance at 31 December 2022		11,445	293,712	181,945	4,920	16,710	3,275	1,945,465	2,457,472

Detail on the movements in the capital reduction reserve can be found in notes 26 and 32. The accompanying notes on pages 22 to 74 are an integral part of the financial statements.

CONSOLIDATED STATEMENT OF CASHFLOWS FOR THE YEAR ENDED 31 DECEMBER
	Note	2022 US$'000	2021 US$'000
Cash provided by/(used in):
Operating activities
Profit before tax		2,240,529	763,139
Adjustments for:
Depletion, depreciation and amortisation	15	662,947	455,913
Exploration and evaluation expenses	14	9,040	156
Impairment charge/(reversal)	19	31,467	(465,271)
Reduction/(increase) in contingent/deferred consideration		4,295	(8,250)
Loan fee amortisation	9	6,418	35,343
Revaluation of financial instruments	29	(16,787)	8,261
Gain on bargain purchase		(1,335,170)	(10,454)
Hedging resets1		(39,680)	(115,362)
Accretion	9	56,511	38,348
Bank interest & charges	9	123,014	120,891
Interest on related party loan	9	17,924	48,278
Interest rate swaps	9	(851)	7,276
Unrealised foreign exchange on cash and cash equivalents		2,464	(1,871)
Share-based payment expenses		14,069	-
Decommissioning expenditure		(65,707)	(27,930)
Operating cash flows before movements in working capital		1,710,483	848,467
Decrease/(increase) in inventories		4,051	(65,302)
Increase in trade and other receivables		(50,575)	(110,955)
Increase in trade and other payables		141,275	250,456
Corporation tax paid		(81,914)	(10,004)
Net cash from operating activities		1,723,320	912,662

CONSOLIDATED STATEMENT OF CASH FLOWS CONTINUED FOR THE YEAR ENDED 31 DECEMBER
	Note	2022 US$'000	2021 US$'000
Investing activities
Capital expenditure		(380,640)	(269,606)
Reverse consideration on acquisition		-	56,456
Acquisition of subsidiaries net of cash acquired	17	(957,452)	(7,000)
Contingent/deferred consideration payment	25	(66,132)	-
Net cash used in investing activities		(1,404,224)	(220,150)
Financing activities
Receipt from issue of equity		299,749	-
Payments for lease liabilities (principal)	24	(34,348)	(3,503)
Loan repayment (third party)		(500,000)	(809,776)
Loan repayment (shareholder)		(273,055)	-
Loan drawdown		550,000	254,999
Bank interest & charges		(142,820)	(85,181)
Interest rate swaps	9	851	(7,276)
Costs of share issue		(7,825)	-
Net cash used in financing activities		(107,448)	(650,737)
Currency translation differences relating to cash		(2,675)	1,872
Increase in cash & cash equivalents		208,973	43,647
Cash and cash equivalents, beginning of period		44,849	1,202
Cash and cash equivalents, end of period		253,822	44,849
1. Hedging resets relate to the amortisation of the deferred reset gains which have been recycled to the current year profit and
loss.
The accompanying notes on pages 22 to 74 are an integral part of the financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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's 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$'000), 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's 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:

• 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;

• 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

• 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 - 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's borrowing arrangements.

Based on their assessment of the Group's 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 CONTINUED

3. Significant accounting policies, judgements and estimation uncertainty continued

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's 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's 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's 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 "key sources of estimation uncertainty" as required by IAS 1 (being those which could have a material impact on the group's 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's 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 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 ('CGU's) include the estimated cost of UK carbon emissions allowances. The recoverable value of CGU's 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 - 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, 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's 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 - 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.

3. Significant accounting policies, judgements and estimation uncertainty continued

Decommissioning provisions

Most of the group's 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's 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's existing exploration and appraisal assets proceed to development, as this is likely to significantly extend the life of the group's 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's oil and gas portfolio, a material adverse change is not anticipated to the carrying value of the Group's 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's share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition is less than the Group's 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's 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. 2

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

3.  Significant accounting policies, judgements and estimation uncertainty continued

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's 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's 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:

• 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;

• 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's 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's 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.

3.  Significant accounting policies, judgements and estimation uncertainty continued

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:

• There is an economic relationship between the hedged item and the hedging instrument;

• The effect of credit risk does not dominate the value changes that result from that economic relationship; and

• 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 - 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 the heading of cash flow hedge reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss, and is included in the 'other gains and losses' line item.

Amounts previously recognised in other comprehensive income and accumulated in equity are reclassified to profit or loss in the periods when the hedged item affects profit or loss, in the same revenue line as the recognised hedged item. However, when the hedged forecast transaction results in the recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognised in other comprehensive income and accumulated in equity are removed from equity and included in the initial measurement of the cost of the non-financial asset or non-financial liability. This transfer does not affect other comprehensive income. Furthermore, if the Group expects that some or all of the loss accumulated in the cash flow hedge reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.

The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in the cash flow hedge reserve is reclassified immediately to profit or loss.

If a hedge of a transaction related item is discontinued part way through the life of the hedge (e.g. due to early termination of the swap, hedging resets), but the hedged item is still expected to occur, the amounts deferred in equity would remain in equity until the earlier of: (i) the hedged transaction occurring; or (ii) expectation that the amount deferred in equity will not be recovered in the future periods.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

3. Significant accounting policies, judgements and estimation uncertainty continued

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 - 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's 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 'underlift', included within accued income or 'overlift', 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's 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 - 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.

3. Significant accounting policies, judgements and estimation uncertainty continued

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 - 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's 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's 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 - Buildings   10 years

Computer and office equipment   3 years

Furniture and fittings   5 years

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

3. Significant accounting policies, judgements and estimation uncertainty continued

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 'measurement period' (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.

3. Significant accounting policies, judgements and estimation uncertainty continued

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's 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

3. Significant accounting policies, judgements and estimation uncertainty continued

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's 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's 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 undiscouted 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   InsuranceContracts

Amendments to IAS 1  ClassificationofLiabilitiesasCurrentorNon-current Amendments to IAS 1 and IFRS Practice Statement 2  Disclosure of Accounting Policies

Amendments to IAS 8   DefinitionofAccountingEstimates

Amendments to IAS 12   DeferredTaxrelatedtoAssetsandLiabilitiesarisingfromaSingleTransaction

Amendments to IFRS 16   LeaseLiabilityinaSaleandLeaseback

Amendments to IAS 1   Non-currentLiabilities 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's accounting policies and that have the most significant effect on the amounts recognised in financial statements.

3. Significant accounting policies, judgements and estimation uncertainty continued

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's 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's 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's 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's estimates of reserves and resource volumes used for accounting purposes are built up from historically matched models for operated assets and principally from operators' estimates for non-operated assets. A review process is undertaken to compare the results of the Group's 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's 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's impairment tests and deferred tax recoverability assessments to key sources of estimation uncertainty including reserves and resources is discussed below.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

3. Significant accounting policies, judgements and estimation uncertainty continued

Estimates in impairment of oil and gas assets and goodwill

Determination of whether the Group's 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's 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's estimates of a market participant's view of pricing and discount rates are supported by an independent consultant.

The sensitivity of the Group's 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's 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's 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 involved.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

3. Significant accounting policies, judgements and estimation uncertainty continued Critical accounting judgements

Acquisitions

In the periods presented, the Group has made a number of acquisitions - 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's 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's segmental reporting structure remained in place for all periods presented and is consistent with the way in which the Group's activities are reported to the Board and Chief Decision Making Officer. The Group's activities are considered to be an individual operating segment due to the nature of the Group's operations being consistent, and such operations existing in a single geographical region that is covered by the same regulations.

5. Revenue
	2022 US$'000	2021 US$'000
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's 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	2021
	US$'000	US$'000
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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

7. Administrative expenses	2022	2021
	US$'000	US$'000
General and administrative	(27,693)	(15,180)
Share-based payment charge (note 33)	(14,069)	-
Transaction costs	(46,089)	-
	(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$'000	2021 US$'000
Wages and salaries	(81,017)	(45,488)
Social security costs	(9,902)	(5,187)
Pension costs	(8,298)	(5,458)
	(99,217)	(56,133)
The average number of employees for the year was as follows:
	2022	2021
Onshore and administrative	268	251
Offshore	249	217
	517	468

7. Administrative expenses continued
Audit fees	2022 US$'000	2021 US$'000
Fees payable to the current Company's auditor for audit of the Company's financial statements	(1,095)	(685)
Fees payable to the previous Company's auditor for audit of the Company's financial statements	-	(35)
Audit of the Company's subsidiaries pursuant to legislation	(279)	(62)
Non-audit fees provided by the current auditors	(4,707)	-
Non-audit fees provided by the previous auditors	-	(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$'000	2021 US$'000
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$'000	2021 US$'000
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	-	(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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

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$'000	2021 US$'000
Earnings for the year:
Earnings for the purpose of basic earnings per share	1,031,532	425,989
Effect of dilutive potential ordinary shares	-	-
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 share1	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$'000	2021 US$'000
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's 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.

11. Trade and other receivables continued
Non-current	2022 US$'000	2021 US$'000
Decommissioning reimbursement	162,710	152,184
Current	2022 US$'000	2021 US$'000
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$'000	2021 US$'000
Prepayments	7,415	8,524
Decommissioning securities	1,640	2,012
	9,055	10,536

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

13. Inventories
Current	2022 US$'000	2021 US$'000
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$'000	2021 US$'000
Hydrocarbon inventories	-	532
14. Exploration and evaluation assets
		US$'000
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	Development and production assets	Other fixed assets	Total
	US$'000	US$'000	US$'000	US$'000
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)	-	-	(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)	-	1,115,023	-	1,115,023
Transfers from exploration and evaluation assets (note 14)	-	75,005	-	75,005
Change in decommissioning estimates (note 23)	-	(278,398)	-	(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	-	-	6,441
Impairment reversal (note 19)	-	465,271	-	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)	-	(30,700)	-	(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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

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's material joint operations as at 31 December are as follows:

Group Net % Interest

Block	Licence	Field/Discovery Name	Operator	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 U.K. 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 (U.K.) 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 (U.K.) Limited	13.70%	13.70%
16/27b	P.345	Britannia	Chrysaor Production (U.K.) 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 (U.K.) Limited	20.00%	0.00%
3/8a and 3/8a	P.199	Columba B/D	CNR International (U.K.) Limited	5.60%	0.00%

16. Interests in joint operations continued

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 U.K. 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 (U.K.) Limited	25.00%	25.00%
23/22a	P.111	Pierce	Enterprise Oil Limited	34.01%	34.01%
15/30a	P.103	Britannia	Chrysaor Production (U.K.) Limited	33.03%	33.03%
21/5a	P.103	Enochdhu	Chrysaor Production (U.K.) Limited	50.00%	50.00%
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 and 204 /15	P.2403	Tornado	Ithaca SP E&P Limited	50.00%	0.00%

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

17. Business combinations The fair values of the identifiable assets and liabilities as at the acquisition dates were:
	MOGL	Siccar	Summit
	2022 US$'000	2022 US$'000	2022 US$'000
Property, plant and equipment (note 15)	322,590	668,700	101,933
Exploration and evaluation assets (note 14)	-	706,558	-
Cash	170,629	88,638	18,799
Inventory	2,781	-	-
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	-	(2,626)	(2,806)
Decommissioning provisions	(253,393)	(121,022)	(16,116)
Financial instruments	-	(82,899)	-
Borrowings	-	(200,000)	-
	(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)	-	-
Contingent consideration	(139,320)	(102,111)	-
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.

17. Business combinations continued

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 ("SPA") are met as follows: set gross export production volume from Montrose Infill Project Phase 1, set cumulative gross export production volume following Arbroath well reinstatements, set gross export production volume from next new well in the Shaw Field and, an amount payable during the Value Sharing Period (1 January 2022 to 31 December 2024) in relation to sales in excess of a set oil trigger price. The amount payable in relation to sales in excess of a set oil trigger price is capped under the terms of the SPA.

The contingent consideration 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 million 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's 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 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

17.  Business combinations continued

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 have 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's 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 million 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$'000	2021 US$'000
Balance at 1 January	722,075	722,075
Additions (note 17)	61,773	-
Balance at 31 December	783,848	722,075
The goodwill is not tax deductible on any of the acquisitions.

18.  Goodwill continued

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$'000	2021 US$'000
D&P assets	(30,700)	465,271
E&E assets	(1,867)	-
Contingent consideration reversal	1,100	-
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's producing assets with the main trigger being the implementation of the Energy Profits Levy ("EPL") in the second half of 2022. The review demonstrated that there was no requirement to impair any of the Group's 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   Priceassumptions (nominal)

	discount rate assumption	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 decrease in discount rate or an increase in forecast revenues would have no material impact on post-tax carrying amounts.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

19.  Impairment (charge)/reversal on oil and gas assets continued

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 million 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   Priceassumptions (nominal)

	discount rate assumption	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$'000	2021 US$'000
Current
Amounts owed to related parties (note 32)	-	(437,076)
	-	(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$'000	2021 US$'000
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.

20.  Borrowings continued

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 million 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 $198m 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 repaid out of proceeds of the IPO.

Reserves Based Lending (RBL) facility

During 2019, the Group's 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 $26.7million 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 million

(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's restricted subsidiaries; incur expenditure on exploration and appraisal activities in excess of approved levels; guarantee certain types of the Group's other indebtedness; expand into unrelated businesses; merge or consolidate with other entities; or enter into certain transactions with affiliates.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

20.  Borrowings continued

The key financial covenants in the RBL are:

• 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. 'Net debt' 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's 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;

• 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);

• 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

• 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$'000	2021 US$'000
At 1 January	(1,437,579)	(1,914,464)
Cash flows	399,373	650,737
Acquisitions	(200,000)	-
Other	(55,834)	(173,852)
At 31 December	(1,292,040)	(1,437,579)
* being interest bearing loans, lease liabilities and interest rate derivatives.
Other movement comprises mainly finance costs, capital contribution and related imputed interest.	2022 US$'000	2021 US$'000
22. Trade and other payables Trade payables	(14,917)	(13,901)
Amounts owed to parent (note 32)	-	(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$'000	2021 US$'000
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's 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 assumptions.

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 years, we anticipate that approximately 33% of the liability will be paid within the next five years.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

24. Lease liabilities
Current	2022 US$'000	2021 US$'000
Lease liability	(41,637)	(3,211)
Non-Current	2022 US$'000	2021 US$'000
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$'000	2021 US$'000
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$'000	2021 US$'000
At 1 January	(3,489)	(6,992)
Additions	(89,717)	-
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$'000	2021 US$'000
Contingent consideration	(101,559)	-
Petrofac deferred consideration	(6,121)	(49,806)
	(107,680)	(49,806)
Non-current	2022 US$'000	2021 US$'000
Contingent consideration	(157,337)	(19,480)
Petrofac deferred consideration	-	(5,804)
MOGL deferred consideration	(61,783)	-
	(219,120)	(25,284)
	2022 US$'000	2021 US$'000
Cash flows relating to contingent and deferred considerations	(66,132)	-
Movement in contingent consideration and deferred consideration is as follows:
	2022 US$'000	2021 US$'000
At 1 January	(75,090)	(67,114)
Business combinations (note 17)	(304,846)	(13,530)
Utilisation	66,132	-
Reversal	1,100	-
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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

25.  Contingent and deferred consideration continued

MOGL

During the year ended 31 December 2022 the Group acquired MOGL which included elements of consideration that are payable upon certain events occuring 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 at 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 occuring 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 agreement.

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$'000
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 £0.88 shares, the conversion of £0.88 shares to £0.01 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 £0.01 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	-	-	-	1,001
Issue of new $0.01 B1 shares and $0.01 B2 shares	-	100	100	-	200
Issue of new $1.00 A ordinary shares	114,000,000	-	-	-	114,000,000
Cancellation of $1.00 A ordinary shares relating to capital reduction	(114,000,000)	-	-	-	(114,000,000)
Conversion of $1.00 A ordinary shares, $0.01 B1 share and 0.01 B2 share to £0.01 A ordinary shares	87,087	(12)	(12)	-	87,063
Bonus Issue of new £0.01 A shares	898,131,843	-	-	-	898,131,843
Bonus Issue of new £0.01 B1 shares	-	1,401,670	-	-	1,401,670
Bonus Issue of new £0.01 B2 shares	-	-	420,440	-	420,440
Conversion of £ 0.01 A ordinary shares, £0.01 B1 shares and £0.01 B2 shares to £0.01 ordinary shares	(898,219,931)	(1,401,758)	(420,528)	900,042,217	-
Bonus issues of £0.01 ordinary shares	-	-	-	120,000	120,000
Issue of new £0.01 ordinary shares on IPO	-	-	-	105,000,000	105,000,000
Issue of new £0.01 ordinary shares on exercise of share options	-	-	-	1,402,759	1,402,759
Ordinary shares of £0.01 each at 31 December 2022	-	-	-	1,006,564,976	1,006,564,976

(b) Share premium	2022	2021
	US$'000	US$'000
Balance at 01 January	634,658	634,658
Share premium cancellation	(634,658)	-
Addition	293,712	-
Balance at 31 December	293,712	634,658
Addition during the year represents the difference between the nominal value of share £0.01 and IPO price of £2.50 per share (net of share issues expenses).

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

26.  Reserves continued

(c) Capital contribution reserve (note 20)	2022	2021
	US$'000	US$'000
Balance at 01 January	114,000	114,000
Capital reduction	(114,000)	-
Addition	181,945	-
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	2021
	US$'000	US$'000
At 31 December	4,920	-
27. Taxation
	2022 US$'000	2021 US$'000
Current tax
Current corporation tax (charge)/credit	(185,946)	14,863
Current corporation tax credit - 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)

27. Taxation continued The tax on the Group's 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$'000	2021 US$'000
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	-
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)	-
Current tax on EPL	(131,389)	-
Prior year adjustments on acquired entities	(3,165)	-
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 changes to the EPL were announced on 17 November 2022 and enacted in December 2022 whereby the Levy was increased to 35% from 1 January 2023 until 31 March 2028, increasing the effective UK ring fenced oil and gas

tax rate to 75% resulting in an additional deferred tax charge during the year to 31 December 2022.

Deferred tax at 31 December relates to the following:
	2022 US$'000	2021 US$'000
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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

27.  Taxation continued

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$'000	2021 US$'000
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	-
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$'000	2021 US$'000
Accelerated capital allowances	(490,246)	(149,117)
Tax losses	(386,819)	(218,174)
Abandonment provision	(124,598)	24,214
Petroleum revenue tax	-	(12,861)
Deferred PRT	4,173	-
Hedging	(226,040)	152,015
Investment allowances	8,617	10,573
	(1,214,913)	(193,350)

27. Taxation continued
		Deferred corporation tax on	Accelerated tax
Gross deferred corporation tax liabilities	Hedges US$000	deferred PRT US$000	depreciation US$000	Total US$000
At 1 January 2021	26,941	-	(536,735)	(509,794)
Reclass to deferred corporation tax assets	(26,941)	-	-	(26,941)
Prior year adjustment	-	-	(15,813)	(15,813)
Origination and reversal of temporary differences	-	(12,861)	(122,731)	(135,592)
At 31 December 2021	-	(12,861)	(675,279)	(688,140)
Prior year adjustment	-	-	(4,347)	(4,347)
Reclassification of decommissioning asset	-	-	(436,771)	(436,771)
Business combinations	-	-	(647,743)	(647,743)
Origination and reversal of temporary differences	-	4,173	(485,985)	(481,812)
At 31 December 2022	-	(8,688)	(2,250,125)	(2,258,813)
	Abandonment provision	Tax losses	Hedges	Total
Gross deferred corporation tax assets	US$000	US$000	US$000	US$000
At 1 January 2021	173,452	718,456	-	891,908
Reclass from deferred corporation tax liabilities	-	-	26,941	26,941
Prior year adjustment	-	14,599	-	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	-	3,706	-	3,706
Reclassification of decommissioning asset	436,772	-	-	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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

27. Taxation continued
Deferred PRT asset	Total $000
At 1 January 2021	-
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's 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 asset of the Group by $780 million.

28. Commitments and contingencies
	2022 US$'000	2021 US$'000
Capital commitments
Capital commitments incurred jointly with other venturers (Group's share)	52,309	83,368

The Group's 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's 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 £341 million and £383 million, respectively, in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

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:

• Level 1 - 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.

• Level 2 - 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.

• Level 3 - inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument's 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's 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	Mandatorily measured at fair value through	Derivatives designated in hedge	Total carrying
	amortised cost $'000	profit or loss $'000	relationships $'000	amount $'000
Financial assets
Cash and cash equivalents	253,822	-	-	253,822
Trade and other receivables	359,994	-	-	359,994
Derivative financial instruments	-	7,125	164,924	172,049
Financial liabilities
Borrowings	(1,213,731)	-	-	(1,213,731)
Trade and other payables	(618,460)	-	-	(618,460)
Lease liability	(58,858)	-	-	(58,858)
Contingent and deferred consideration	(67,904)	(258,896)	-	(326,800)
Derivative financial instruments	-	(57,546)	(106,563)	(164,109)
				(1,596,093)

29. Financial instruments continued The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2021 are set out below:
	Measured at	Mandatorily measured at fair value through	Derivatives designated in hedge	Total carrying
	amortised cost $'000	profit or loss $'000	relationships $'000	amount $'000
Financial assets
Cash and cash equivalents	44,849	-	-	44,849
Trade and other receivables	228,290	-	-	228,290
Derivative financial instruments	-	-	5,108	5,108
Financial liabilities
Borrowings	(1,391,692)	-	-	(1,391,692)
Trade and other payables	(427,726)	-	-	(427,726)
Lease liability	(3,489)	-	-	(3,489)
Contingent and deferred consideration	(19,480)	(55,610)	-	(75,090)
Derivative financial instruments	-	(2,009)	(457,293)	(459,302)
				(2,079,052)
The following table presents the Group's material financial instruments measured at fair value for each hierarchy level as of 31 December 2022:
	Level 1 US$'000	Level 2 US$'000	Level 3 US$'000	Total Fair Value US$'000
Contingent consideration (note 25)	-	(35,650)	(223,246)	(258,896)
Derivative financial instrument asset	-	172,049	-	172,049
Derivative financial instrument liability	-	(164,109)	-	(164,109)
Movement in level 3 financial instruments in the 12 months to 31 December 2022 is as follows:
				US$'000
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)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

29. Financial instruments continued The following table presents the Group's material financial instruments measured at fair value for each hierarchy level as of 31 December 2021:
	Level 1 US$'000	Level 2 US$'000	Level 3 US$'000	Total Fair Value US$'000
Contingent consideration (note 25)	-	-	(19,480)	(19,480)
Derivative financial instrument asset	-	5,108	-	5,108
Derivative financial instrument liability	-	(459,302)	-	(459,302)
Movement in level 3 financial instruments in the 12 months to 31 December 2021 is as follows:
				US$'000
At 1 January 2021				(14,200)
Additions				(13,530)
Changes in fair value				8,250
At 31 December 2022				(19,480)
The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of profit or loss:
			2022 US$'000	2021 US$'000
Revaluation of forex forward contracts			(28,172)	(8,261)
Revaluation of commodity hedges			44,959	-
			16,787	(8,261)
Realised (loss)/gain on commodity hedges			(16,215)	7,808
Total gain/(loss) on financial instruments			572	(453)

29. Financial instruments continued 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$'000	2021 US$'000
Revaluation gain/(loss) of derivative contracts	492,900	(371,213)
Realised loss on derivative contracts	(582,445)	(330,629)
Amounts recycled to revenue	501,513	196,181
Amounts recycled to revenue - oil put premiums	14,629	27,179
Amounts recycled to revenue - gas put premiums	42,347	14,627
Amounts recycled to finance costs - 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's 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's 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's 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's target is to hedge oil and gas prices up to a maximum of 75% of the next 12 months' 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	-	bbls	n/a
Oil swaps	Jan 23 - Jun 24	3,390,500	bbls	$70/bbl
Oil collars	Jan 23 - Dec 23	4,560,000	bbls	$68/bbl floor - $91/bbl ceiling
Gas swaps	Jan 23 - Jun 24	104,585,000	therms	188p/therm
Gas puts	Apr 23 - Sep 23	9,150,000	therms	220p/therm
Gas collars	Jan 23 - Mar 24	100,200,000	therms	244p/therm floor - 479p/therm ceiling

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

29. Financial instruments continued
The below represents total commodity hedges in place at the 2021 year end: Derivative	Term	Volume		Average price
Oil puts	Jan 22 - Dec 22	2,080,500	bbls	$64/bbl
Oil swaps	Jan 22 - Dec 23	4,851,984	bbls	$56/bbl
Oil collars	Jan 22 - Dec 23	3,558,750	bbls	$58/bbl floor - $80/bbl ceiling
Gas swaps	Jan 22 - Dec 22	203,900,000	therms	64p/therm
Gas puts	Jan 22 - Dec 23	36,500,000	therms	40p/therm
Gas collars	Jan 22 - Dec 23	73,000,000	therms	60p/therm floor - 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's 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$'000	2021 US$'000
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 - 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 - Dec 23	$50 million	0.22%

29. Financial instruments continued

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's 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$'000	2021 US$'000
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 £5.5 million per quarter hedged at an average forward rate of $1.265:£1 for the period January to December 2023. As at 31 December 2021 the Group had an average of £16 million per quarter hedged at an average forward rate of $1.375:£1 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's 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's exposure to foreign currency changes for all other currencies is not material.

Change in GBP foreign exchange rate	2022 US$'000	2021 US$'000
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's 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' 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's 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's 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's 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

29. Financial instruments continued

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$'000 Within 2 to 5 years US$'000 More than 5 Years US$'000 Trade and other payables (618,460) - - Derivatives (136,668) (27,440) - Contingent and deferred consideration (116,518) (279,780) - Lease liabilities (41,257) (17,439) - Borrowings (56,250) (1,382,411) - (969,153) (1,707,070) - The following table shows the timing of cash outflows, including future interest, relating to financial liabilities at 31 December 2021: Within 1 year Within 2 to 5 years More than 5 years US$'000 US$'000 US$'000 Trade and other payables (484,268) - - Derivatives (438,006) (21,296) - Contingent and deferred consideration (49,806) (25,284) - Lease liabilities (2,094) (1,617) Borrowings (437,076) (1,025,435) - (1,411,250) (1,073,632) -

-

vi) Capital management

The Group's objectives when managing capital are to safeguard the Group's 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's financial results.

30. Derivative financial instruments
	2022 US$'000	2021 US$'000
Oil swaps - cash flow hedge	(28,685)	(102,704)
Oil swaps- non-cash flow hedge	(15,027)	-
Oil collars - cash flow hedge	(21,983)	(6,542)
Oil puts - cash flow hedge	-	(9,402)
Gas swaps - cash flow hedge	19,797	(264,345)
Gas swaps- non-cash flow hedge	(29,271)	-
Gas puts - cash flow hedge	9,746	(3,317)
Gas collars - cash flow hedge	79,489	(66,007)
Interest rate swaps - cash flow hedge	-	133
Interest rate swaps- non-cash flow hedge	7,125	-
FX forwards - non-cash flow hedge	(13,250)	(2,010)
	7,941	(454,194)
Maturity analysis of derivative financial instruments	2022 US$'000	2021 US$'000
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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

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$'000 Carrying Amount	Fair Value		2021 US$'000 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's 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:

% equity interest at 31 December

	Registered office	Country of incorporation	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	-	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%	-
Ithaca SP Bonds PLC (formerly Siccar Point Energy Bonds PLC)**	4	England and Wales	100%	-
Ithaca SP Finance Limited (formerly Siccar Point Energy Finance Limited)**	4	England and Wales	100%	-
Ithaca SP (Holdings) Limited (formerly Siccar Point Energy (Holdings) Limited)**	4	England and Wales	100%	-

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

32.  Related party transactions continued

% equity interest at 31 December

	Registered office	Country of incorporation	2022	2021
Ithaca SP (E&P) Limited (formerly Siccar Point Energy E&P Limited)**	4	England and Wales	100%	-
Ithaca SP (O&G) Limited (formerly Siccar Point Energy U.K. Limited)**	4	England and Wales	100%	-
Ithaca SPE Limited (formerly Siccar Point Energy Limited)**	4	England and Wales	100%	-
Ithaca Zeta Limited (formerly Summit Exploration and Production Limited)**	4	England and Wales	100%	-

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's Road, Aberdeen, Scotland AB15 4YL
3. Canon's 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. Borgartúni 26, 105 Reykjavík, 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 - principal amount (note 20)	2022 US$'000	2021 US$'000
Subordinated loan due to DKL Energy Limited	-	(63,000)
Capital Notes issued to DKL Energy Limited	-	(374,076)
	-	(437,076)
Amounts due to parent (note 22)	2022 US$'000	2021 US$'000
Delek Group Limited	-	(28,941)
Subordinated loan due to DKL Energy Limited	-	(14,090)
Other amounts owed to parent	-	(377)
	-	(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.

32. Related party transactions continued The following table provides breakdown of amounts settled under the waiver agreement: Outstanding Balance Repayment of loans Loan Waiver Status of outstanding loans as of 8 November 2022 US$'000 US$'000 US$'000 Subordinated loan due to DKL Energy Limited (63,000) 63,000 Subordinated loan due to DKL Energy Limited (interest) (14,406) 14,406 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$'000	2021 US$'000
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	-
	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	-	-	-	-
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	-	-	-	-
Exercise price	$nil	$nil	$nil	N/A
Weighted average remaining life	0.9 years	2.9 years	3.3 years	N/A

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

33. Share-based payments continued

All LTIP awards are nil-cost options. There are no performance conditions attaching to the Heritage and At-IPO awards. The fair values of all the LTIP awards were determined based on the share price on date of award. The Heritageawardsvestovertheperiodto14November2023,theAt-IPOawardsvestovertheperiodto14November2025andthe2022awardsvestovertheperiodto1April2026.ItisanticipatedthatfutureexercisesofLTIPawardswillbesettledbyequity.ThetotalchargeforLTIPshareoptionsintheyearto31December2022was$0.6million(2021:$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 £0.01. Mr Myerson's share options vested immediately on IPO and Mr Bruce's 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 IPO-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	-	-	-
Granted during the year	2,337,931	2,337,931	4,675,862
Exercised during the year	(1,402,759)	-	(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	£0.01	£0.01	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 £0.01 each and 420,528 B2 shares of £0.01 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:

Percentage vesting

Period	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.

33.  Share-based payments continued

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.

Non-GAAP measures

The Group uses certain performance metrics that are not specifically defined under International Financial Reporting Standards or other generally accepted accounting principles. These non-GAAP measures which are presented

in the Annual Report and Accounts are defined below:

Adjusted EBITDAX: earnings before interest, tax, put premiums on oil and gas derivative instruments, revaluation of forex forward contracts, revaluation of commodity hedges, depletion depreciation and amortisation, impairment (charge)/reversal, exploration and evaluation expenditure, fair value gains/(losses) on contingent consideration, gain on bargain purchase and transaction costs. This measure is considered as an indicator of underlying financial performance. Adjusted EBITDAX is reconciled to profit after tax as follows:

	2022 $m	2021 $m
Profit after tax	1,031.5	426.0
Taxation charge	1,209.0	337.2
Gain on bargain purchase	(1,335.2)	(10.5)
Depletion, depreciation and amortisation	662.9	455.9
Impairment charge/(reversal)	31.5	(465.3)
Net finance costs	203.0	250.1
Oil and gas put premiums	56.9	41.8
Revaluation of foreign exchange forward contracts	28.2	8.3
Revaluation of commodity hedges	(45.0)	-
Transaction costs	60.1	-
Exploration and evaluation expenses	9.0	0.2
Fair value charge/(gain) on contingent consideration	4.3	(8.3)
Adjusted EBITDAX	1,916.2	1,035.4

Adjusted net income: Profit after tax excluding non-cash bargain purchase credits and non-cash EPL deferred tax charges. Adjusted net income is reconciled to profit after tax as follows:
	2022 $m	2021 $m
Profit after tax	1,031.5	426.0
Gain on bargain purchase	(1,335.2)	(10.5)
EPL deferred tax charge	766.5	-
Adjusted net income	462.8	415.5

Adjusted earnings per share (EPS): Adjusted net income divided by average shares for the year of 1,005.2m (2021: 1,005.2m)

Net debt: consists of amounts outstanding under RBL facility and senior secured loan notes less cash and cash equivalents and excludes intragroup debt arrangements or liabilities represented by letters of credit and surety bonds. Net debt comprises:

	2022 $m	2021 $m
RBL drawn facility	(600.0)	(350.0)
Senior unsecured notes	(625.0)	(625.0)
Cash and cash equivalents	253.8	44.8
Net debt	(971.2)	(930.2)

Leverage ratio: net debt at the end of the year divided by adjusted EBITDAX for the year then ended. The calculations are as follows:	2022	2021
Net debt ($m)	971.2	930.2
Adjusted EBITDAX ($m)	1,916.2	1,035.4
Leverage ratio	0.5x	0.9x

Available liquidity: the sum of cash and cash equivalents on the balance sheet and the undrawn amounts available to the Group using existing approved third-party facilities less restricted cash. Available liqiodity comprises:

	2022 $m	2021 $m
Cash and cash equivalents	253.8	44.8
Undrawn borrowing facilities	325.0	575.0
Available liquidity	578.8	619.8

Group free cash flow: net cash flow from operating activities less cash used in investing activities, adding back acquisition of subsidiaries net of cash acquired, less bank interest and interest rate swaps. Group free cash flow reconciles to net cash flow from operating activities as follows:

	2022 $m	2021 $m
Net cash flow from operating activities	1,723.3	912.7
Net cash used in investing activities	(1,404.2)	(220.2)
Add back acquisitions	957.5	7.0
Bank interest and charges	(142.8)	(85.2)
Interest rate swaps	0.9	(7.3)
Group free cash flow	1,134.6	550.5
Unit operating expenditure: operating costs (excluding over/underlift) including tariff expense tariff income and tanker costs divided by net production for the year.
DD&A rate per barrel: depletion, depreciation and amortisation charge for the year divided by net production for the year.
Other key performance indicators Total production: historic production boe/d include volumes from date of acquisition of MOGL on 4 February 2022 and Siccar Point Energy and Summit on 30 June 2022.

 

END

 

 

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