Results for the year ended 31 December 2022

RNS Number : 3963V

EnQuest PLC

05 April 2023

EnQuest PLC

Results for the year ended 31 December 2022 and 2023 outlook

5 April 2023

Unless otherwise stated, all figures are on a Business performance basis and are in US Dollars.

Comparative figures for the Income Statement relate to the period ended 31 December 2021 and the Balance Sheet as at 31 December 2021. Alternative performance measures are reconciled within the 'Glossary - Non-GAAP measures' at the end of the Financial Statements.

EnQuest Chief Executive, Amjad Bseisu, said:

"Throughout 2022, we continued to demonstrate progress against our strategic priorities of "deliver, de-lever and grow". Production was at the mid-point of our guidance range, we generated significant free cash flow of $518.9 million and reduced our year end net debt to $717.1 million, its lowest level since 2014. We also refinanced our debt facilities, materially extending their maturities.

"We continue to progress our new energy and decarbonisation ambitions at the Sullom Voe Terminal and delivered a 24 well abandonment programme, the largest multi-asset well decommissioning campaign seen in the UK Northern North Sea, demonstrating strong capability as a transition company. Our integrated, capability-led business model and our advantaged tax position in the UK enhance our ability to pursue accretive M&A.

"We have continued to perform well against our full year targets. Production to the end of March has averaged around 47,800 Boepd and we have further reduced our net debt, which was down to $624.3 million at the end of February.

"Throughout 2023, we will remain focused on driving performance in our Upstream and Decommissioning businesses while pursuing our decarbonisation and new energy opportunities in a capital-light manner. We also intend to pursue balanced and disciplined capital allocation that will include shareholder returns in the near future.

"With our differentiated business model and the resilience, creativity and adaptability of our people, we are well positioned to deliver on our plans for the future."

2022 performance

§ Group net production averaged 47,259 Boepd (2021: 44,415 Boepd¹), reflecting improved performances at Magnus and PM8/Seligi and the contribution from Golden Eagle

§ Revenue and other operating income of $1,839.1 million (2021: $1,320.3 million) and adjusted EBITDA of $979.1 million (2021: $742.9 million) reflecting materially higher oil prices and higher production

§ Cash generated from operations was $1,026.1 million (2021: $756.9 million)

§ Cash capital expenditure of $115.8 million (2021: $51.8 million)

§ Cash decommissioning expenditure of $59.0 million (2021: $65.8 million)

§ Strong free cash flow generation² of $518.9 million (2021: $396.8 million)

§ Cash and available facilities amounted to $348.9 million at 31 December 2022 (2021: $318.7 million), with EnQuest net debt reduced to $717.1 million (2021: $1,222.0 million)

§ Statutory reported loss after tax was $41.2 million (2021: profit after tax of $377.0 million), primarily driven by the recognition of a non-cash deferred tax liability associated with the UK Energy Profits Levy

¹ 2021 includes Golden Eagle contribution for the period 22 October to 31 December, averaged over the 12 months to the end of December

² Net change in cash and cash equivalents less acquisition costs and net repayments/proceeds from loans and borrowing and share issues

2023 performance and outlook

§ Year to date March production averaged around 47,800 Boepd

§ Net debt amounted to $624.3 million at 28 February 2023

§ During the first quarter of 2023, the Group repaid $118.0 million of its reserves-based lending facility, with drawings reduced to $282.0 million

§ Hedges in place for c.7.9 MMbbls of oil, predominantly through the combination of puts and costless collars. The average floor price is $58/bbl and the ceiling associated with the 3.3 MMbbls of costless collars is $75/bbl

§ 2023 full year average net Group production expected to be between 42,000 and 46,000 Boepd

§ Full year operating costs are expected to be c.$425.0 million

§ Cash capital expenditure is expected to be c.$160.0 million

§ Cash decommissioning expenditure is expected to be c.$60.0 million

Production and financial information

Business performance measures	2022	2021	Change %
Production (Boepd)	47,259	44,415	6.4
Revenue and other operating income ($m)¹	1,839.1	1,320.3	39.3
Realised oil price ($/bbl)^1,2	88.9	68.6	29.6
Average unit operating costs ($/Boe)²	22.7	20.5	10.7
Adjusted EBITDA ($m)²	979.1	742.9	31.8
Cash expenditures ($m)	174.8	117.6	48.6
Capital²	115.8	51.8	123.6
Decommissioning	59.0	65.8	(10.3)
Free cash flow ($m)²	518.9	396.8	30.8
	End 2022	End 2021
EnQuest net (debt)/cash ($m)²	(717.1)	(1,222.0)	(41.3)

Statutory measures	2022	2021	Change %
Reported revenue and other operating income ($m)³	1,853.6	1,265.8	46.4
Reported gross profit ($m)	652.9	358.2	82.3
Reported profit/(loss) after tax ($m)	(41.2)	377.0	-
Reported basic earnings/(loss) per share (cents)	(2.2)	21.7	-
Cash generated from operations ($m)	1,026.1	756.9	35.6
Net increase/(decrease) in cash and cash equivalents ($m)	39.1	67.4	(42.0)

Notes:

¹ Including realised losses of $203.7 million (2021: realised losses of $67.7 million) associated with EnQuest's oil price hedges

² See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 63. 2021 cash capital expenditure includes $13.2 million associated with the PM8/Seligi riser replacement

³ Including net realised and unrealised losses of $189.3 million (2021: net realised and unrealised gains of $122.2 million) associated with EnQuest's oil price hedges

Production details

Average daily production on a net working interest basis	1 Jan 2022 to 31 Dec 2022	1 Jan 2021 to 31 Dec 2021
	(Boepd)	(Boepd)
UK Upstream
- Magnus	12,641	11,870
- Kraken	18,394	21,964
- Golden Eagle¹	6,323	1,701
- Other Upstream²	3,443	3,685
UK Upstream	40,801	39,220
UK Decommissioning ³	- 337	167
Total UK	40,801	39,387
Total Malaysia	6,458	5,028
Total EnQuest	47,259	44,415

¹ 2021 figure includes Golden Eagle contribution for the period 22 October to 31 December, averaged over the 12 months to the end of December

² Other Upstream: Scolty/Crathes, Greater Kittiwake Area and Alba

³ UK Decommissioning: the Dons

2022 performance summary

Strong production performance, cost control and the supportive commodity price environment underpinned record free cash flow generation. This enabled the Group to refinance its debt facilities, rebalancing the capital structure between secured and unsecured debt and extending maturities until 2027, and reduce EnQuest net debt to $717.1 million. The EnQuest net debt to adjusted EBITDA ratio at the end of 2022 was 0.7x, down from 1.6x at the end of 2021, which shows excellent progress towards the target of 0.5x. The Group also advanced its new energy and decarbonisation ambitions at the Sullom Voe Terminal, identifying and maturing three discrete and scalable decarbonisation opportunities of carbon capture and storage ('CCS'), electrification and green hydrogen and derivative production, while continuing to reduce total Group Scope 1 and 2 CO₂ equivalent emissions. In Decommissioning, 24 wells at Heather and Thistle were decommissioned during the year, one of the most productive campaigns seen in the UK North Sea.

Production of 47,259 Boepd reflected a full year's contribution from Golden Eagle and improved performances at Magnus and PM8/Seligi following successful well programmes and improved uptime at Magnus, while production at Kraken was at the top end of its guidance range. These improvements were partially offset by well integrity issues at Magnus, compressor downtime at PM8/Seligi and natural declines across the portfolio.

Adjusted EBITDA, cash generated by operations and free cash flow were $979.1 million, $1,026.1 million and $518.9 million, respectively, with the material increases from 2021 reflecting higher production and market prices. Capital expenditure of $115.8 million primarily reflected the well programmes at Magnus, PM8/Seligi and Golden Eagle, while cash decommissioning expenditure of $59.0 million was focused on well plug and abandonment ('P&A') activities at Heather and Thistle.

Liquidity and net debt

At 31 December 2022, EnQuest net debt was $717.1 million, down $504.9 million from $1,222.0 million at 31 December 2021. During the year, EnQuest successfully refinanced its debt facilities, rebalancing the capital structure between secured and unsecured debt and extending maturities until 2027. At 31 December 2022, cash drawings under the reserve based lending ('RBL') facility were $400.0 million against a commitment of $500.0 million, while total cash and available facilities were $348.9 million, including restricted funds and ring-fenced funds held in joint venture operational accounts totalling $174.3 million.

EnQuest net debt as at 28 February 2023 was further reduced to $624.3 million, including a working capital benefit of c.$50 million which is expected to reverse, with cash and available facilities of $330.1 million.

During the first quarter of 2023, the Group made repayments totalling $118.0 million reducing cash drawn under the RBL facility to $282.0 million at 31 March 2023 and ensuring the Group remains ahead of its accelerated amortisation requirements following the revisions made to UK Energy Profits Levy ('EPL').

EnQuest remains focused on its strong balance sheet and its ongoing deleveraging strategy. As part of this financial policy, the Group will continue to assess funding opportunities across markets to optimise the capital structure and manage its debt facilities.

Reserves and resources

Net 2P reserves at the end of 2022 were c.190 MMboe (2021: reported c.194 MMboe). During the year, the Group produced c.17 MMboe. This reduction was partially offset by transfers from 2C resources net of other technical revisions, combined with the Group changing its reporting of 2P reserves in Malaysia to an equity working interest basis (from an entitlement basis) to align with peers. This change in reporting added c.11 MMboe to the year-end 2022 balance (c.11 MMboe was also added to the previously reported 2021 figure to align comparatives) . Net 2C resources were c.393 MMboe (2021: c.402 MMboe), with the decrease a result of progression to 2P reserves, as noted above.

Environmental, Social and Governance

The Group has continued to make excellent progress in reducing its absolute Scope 1 and 2 emissions, with CO₂ equivalent emissions reduced by c.23% since 2020, reflecting lower flaring and lower fuel gas and diesel usage. Following offshore modifications to metering systems in Malaysia, the Group is now able to have its Malaysian emissions data independently verified in accordance with the Streamlined Energy and Carbon reporting guidance. This also required harmonisation of reporting methodologies across the Group, which has led to minor restatements of Malaysian emissions data for prior periods to ensure consistency of comparatives provided. Since 2018, UK Scope 1 and 2 emissions have reduced by c.43%, which is significantly ahead of the UK Government's North Sea Transition Deal target of achieving a 10% reduction in Scope 1 and 2 CO₂ equivalent emissions by 2025 and close to the 50% reduction targeted by 2030. The Group continues to mature three discrete and scalable decarbonisation opportunities of CCS, electrification and green hydrogen and derivative production as part of its Infrastructure and New Energy business, with initial CCS feasibility studies indicating the capability to support a project that could store up to 10 million tonnes of CO₂ per annum, which is a multiple of the Group's existing emissions footprint, providing the opportunity to go beyond net zero.

The health, safety and wellbeing of our employees is our top priority. In 2022, EnQuest achieved an upper quartile Lost Time Incident ('LTI') frequency¹ rate. However, there was an increase in the number of LTIs from 2021 for which intervention was undertaken, emphasising increased focus on situational awareness and dynamic risk assessment.

¹ Lost Time Incident frequency represents the number of incidents per million exposure hours worked (based on 12 hours for offshore and eight hours for onshore)

Effective succession planning remains a key focus area for the Board, Governance and Nomination Committee and management. In August, Jonathan Swinney stepped down from the Board as Chief Financial Officer ('CFO') and Executive Director, with Salman Malik, who had long been identified as a potential CFO successor, succeeding him. In addition, following the Group's Annual General Meeting in June, Philip Holland stepped down from the Board as part of an orderly and planned succession process with Rani Koya succeeding him, having joined the Board on 1 January 2022. In December 2022, Gareth Penny was appointed to the Board as Non-Executive Chairman, succeeding Martin Houston. Gareth is currently the chairman of Ninety One Plc, a FTSE 250 financial institution, having previously served on the board of Julius Baer Group for 12 years.

During the year, the Board agreed to adopt the Women Leaders Review target of 40% female representation on the Board and reviewed and supported work being undertaken throughout the organisation to create a more inclusive workplace. The Board currently has 33% female representation and remains ahead of the Parker Review target with respect to minority ethnic representation, with four minority ethnic board members.

In early 2023, the Safety, Climate and Risk Committee was renamed the Safety, Sustainability and Risk Committee, recognising its scope to manage sustainability risks and opportunities within the broader ESG framework.

2023 performance and outlook

Group net production averaged around 47,800 Boepd to the end of March. For the full year, the Group's net production is expected to be between 42,000 and 46,000 Boepd, including the drilling campaigns at Magnus and Golden Eagle. Required maintenance activities are planned to be executed during two separate ten-day periods of single train operations at Kraken, with further extensive shutdowns at each of Magnus and GKA.

Operating expenditures are expected to be approximately $425.0 million, with the increase from 2022 largely due to inflationary pressures and phasing of activities.

Cash capital expenditure is expected to be around $160.0 million. The Group plans to execute a three-well drilling campaign at Magnus and complete the 2022 drilling campaign at Golden Eagle, where two further platform wells are expected to be drilled, commencing later in the year, subject to joint venture approval.

Decommissioning expenditure is expected to total approximately $60.0 million, primarily reflecting ongoing well P&A decommissioning programmes at the Heather/Broom and Thistle/Deveron fields.

For 2023, EnQuest has hedged c.7.9 MMbbls of oil, predominantly through the combination of puts and costless collars. The average floor price is $58/bbl and the ceiling associated with the 3.3 MMbbls of costless collars is $75/bbl. For 2024, EnQuest has hedged c.3.2 MMbbls of oil with an average floor price of c.$60/bbl in the form of puts, with the call element of the existing costless collars having been bought back during the first quarter of 2023.

Summary financial review of 2022

(all figures quoted are in US Dollars and relate to Business performance unless otherwise stated)

Overview

The Company continued to make progress against its strategic aims during 2022. The combination of higher production, higher prices and cost control and capital discipline drove strong free cash flow generation of $518.9 million, up 30.8% compared to 2021. This enabled a 41.3% reduction in EnQuest net debt, which was reduced by $504.9 million to $717.1 million (2021: $1,222.0 million). This rapid deleveraging and increased adjusted EBITDA of $979.1 million, up 31.8% compared to 2021 ($742.9 million), has resulted in a leverage ratio of 0.7x (2021: 1.6x), which is excellent progress towards the Group's leverage target of 0.5x. In addition, the Group completed a comprehensive refinancing of its debt facilities during 2022, reducing the level of gross borrowings and extending the maturities by five years to 2027. This refinancing was a significant achievement given the volatile backdrop in financial markets. Subsequently, the impact of the EPL was included in the Group's reserve based lending ('RBL') facility redetermination for the first half of 2023, resulting in a reduction of the available RBL capacity and liquidity available to the Group, with an accelerated RBL repayment profile. In the first quarter of 2023, the amount drawn on the RBL facility was reduced by $118.0 million to $282.0 million, ensuring the Group remains ahead of the amended amortisation profile.

Income statement

Revenue for 2022 was $1,839.1 million, 39.3% higher than in 2021 ($1,320.3 million) primarily reflecting higher realised prices and higher production. The Group's commodity hedge programme resulted in realised losses of $203.7 million in 2022 (2021: losses of $67.7 million) which reflected the timing at which the hedges were entered into and the increase in market prices during the year, particularly following the Russian invasion of Ukraine in February (see note 27 for further information on the Group's hedging position). The Group's average realised oil price excluding the impact of hedging was $102.6/bbl in 2022, 40.5% higher than 2021 ($73.0/bbl). The Group's average realised oil price including the impact of hedging was $88.9/bbl in 2022, 29.6% higher than 2021 ($68.6/bbl).

Cost of sales were $1,195.8 million for the year ended 31 December 2022, 32.8% higher than in 2021 ($900.4 million).

The Group's operating costs increased by $75.5 million to $396.5 million, primarily reflecting higher production costs, including the full year impact of Golden Eagle, higher fuel and emission trading scheme costs due to higher market prices and lower lease charter credits reflecting high uptime at Kraken, partially offset by a weakening of the Sterling to US Dollar exchange rate. Unit operating costs (excluding hedging) increased by 10.7% to $22.7/Boe (2021: $20.5/Boe), reflecting the impacts on costs noted above. Unit operating costs including hedging were $23.0/Boe (2021: $19.8/Boe).

Total costs of sales also included non-cash depletion expenses of $327.0 million, which were 7% higher than in 2021 ($305.6 million), mainly reflecting the impact of Golden Eagle.

The credit relating to the Group's lifting position and inventory was $15.6 million (2021: charge of $62.3 million). This primarily reflects the reversal of the net overlift position of $18.0 million at 31 December 2021, resulting in a $0.8 million net underlift position at 31 December 2022.

Other cost of operations of $487.8 million were materially higher than in 2021 ($211.5 million), principally as a result of higher Magnus-related third-party gas purchases of $452.8 million (2021: $199.6 million) following the increase in associated market prices.

The tax charge for 2022 of $322.5 million (2021: $53.7 million tax charge), excluding exceptional items, reflects the tax impact on the Group's increased profit before tax and the enactment of the UK EPL. Ring Fence Expenditure Supplement ('RFES') on UK activities, which would historically have provided an offset to the UK tax charge, ceased to be available to claim from the end of 2021.

UK North Sea corporate tax losses at the end of the year decreased to $2,497.7 million (2021: $3,011.0 million). This significant tax loss position provides EnQuest with a strategic advantage in the UK North Sea, enhancing the relative value of assets in EnQuest's hands when compared to other tax paying participants.

Remeasurements and exceptional items resulting in a post-tax net loss of $253.6 million have been disclosed separately for the year ended 31 December 2022 (2021: profit of $156.7 million). Revenue included unrealised gains of $14.5 million in respect of the mark-to-market movement on the Group's commodity contracts, primarily reflecting the recycling of 2021 unrealised hedge losses into business performance during 2022 (2021: unrealised losses of $54.5 million). A non-cash net impairment charge of $81.0 million (2021: impairment reversal of $39.7 million) on the Group's oil and gas assets arises from the impact on future cash flows following the introduction of the EPL, updated asset profiles and a higher discount rate, partially offset by higher forecast oil prices. Other expense includes a $233.6 million charge in relation to the fair value recalculation of the Magnus contingent consideration reflecting a forecast increase in Magnus future cash flows due to higher forecast oil prices and asset profile and cost assumption changes (2021: $140.1 million gain). Other finance costs mainly relate to the unwinding of discount on contingent consideration from the acquisition of Magnus and associated infrastructure of $36.4 million (2021: $58.4 million). A net tax credit of $78.0 million (2021: credit of $78.2 million) has been presented as exceptional, representing the tax effect on the items above and the non-cash recognition of undiscounted deferred tax assets of $127.0 million given the net effect of Group's higher long-term oil price assumptions and changes in asset profiles, partially offset by the initial recognition of the deferred tax liability associated with the EPL of $178.3 million.

Cash flow and EnQuest net debt

The Group's reported cash generated from operations for the year ended 31 December 2022 were $1,026.1 million, up 35.6% compared to 2021 ($756.9 million) primarily driven by materially higher revenue. Free cash flow for 2022 was $518.9 million (2021: $396.8 million). These strong free cash flows enabled the Group to make early voluntary repayments on the previous RBL facility resulting in the balance being repaid in full prior to the RBL being refinanced in October 2022 with commitments of $500.0 million.

In April 2022, the Group partially refinanced its 7% Sterling retail bond ('7.00% retail bond') through an exchange and open offer in the form of a new 9% Sterling retail bond ('9.00% retail bond'), raising £133.3 million

In July, August and September, the Group bought back and cancelled $34.9 million of it 2023 7.00% high yield bond, leaving $792.3 million outstanding. This was subsequently repaid in full in October 2022 utilising $400.0 million of drawdowns from the Group's refinanced RBL, along with operating cash flows and the net proceeds from the issue of a new 11.625% high yield bond.

The EPL has been included in the RBL review and redetermination for the first half of 2023, resulting in a reduction of the available RBL capacity and liquidity available to the Group, with an accelerated RBL repayment profile. During the first quarter of 2023, the Group made repayments totalling $118.0 million, reducing cash drawn under the RBL facility to $282.0 million, ensuring the Group remains ahead of its accelerated amortisation requirements following redetermination. EnQuest net debt as at 28 February 2023 was further reduced to $624.3 million, including a working capital benefit of c.$50 million which is expected to reverse, with cash and available facilities of $330.1 million.

Looking forward, the EPL has also had implications for EnQuest's capital allocation strategy as it limits the cash available for further deleveraging, capital investment and shareholder returns. However, the Group is optimising its capital expenditures in respect of available investment allowances and is confident of further deleveraging through 2023, with shareholder returns to follow in the future.

- Ends -

For further information, please contact:

EnQuest PLC	Tel: +44 (0)20 7925 4900
Amjad Bseisu (Chief Executive)
Salman Malik (Chief Financial Officer)
Ian Wood (Head of Investor Relations, Communications & Reporting)
Craig Baxter (Senior Investor Relations & Communications Manager)

Teneo	Tel: +44 (0)20 7353 4200
Martin Robinson Martin Pengelley
Harry Cameron

Presentation to Analysts and Investors
A presentation to analysts and investors will be held at 09.30 today - London time. The presentation will be accessible via a webcast by clicking here .

EnQuest investor relations team will be hosting a presentation via Investor Meet Company, primarily focused on the Company's retail investors on 19 April at 14:00 - London time.

The presentation is open to all existing and potential shareholders. Questions can be submitted pre-event via your Investor Meet Company dashboard up until 9am the day before the meeting or at any time during the live presentation.

Investors can sign up to Investor Meet Company for free and add to meet ENQUEST PLC via:

https://www.investormeetcompany.com/enquest-plc/register-investor

Investors who already follow ENQUEST PLC on the Investor Meet Company platform will automatically be invited.

Notes to editors

This announcement has been determined to contain inside information. The person responsible for the release of this announcement is Chris Sawyer, General Counsel and Company Secretary.

ENQUEST

EnQuest is providing creative solutions through the energy transition. As an independent energy company with operations in the UK North Sea and Malaysia, the Group's strategic vision is to be the partner of choice for the responsible management of existing energy assets, applying its core capabilities to create value through the transition.

EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm.

Please visit our website www.enquest.com for more information on our global operations.

Forward-looking statements: This announcement may contain certain forward-looking statements with respect to EnQuest's expectations and plans, strategy, management's objectives, future performance, production, reserves, costs, revenues and other trend information. These statements and forecasts involve risk and uncertainty because they relate to events and depend upon circumstances that may occur in the future. There are a number of factors which could cause actual results or developments to differ materially from those expressed or implied by these forward-looking statements and forecasts. The statements have been made with reference to forecast price changes, economic conditions and the current regulatory environment. Nothing in this announcement should be construed as a profit forecast. Past share performance cannot be relied upon as a guide to future performance.

Chief Executive's report

All figures quoted are in US Dollars and relate to Business performance unless otherwise stated.

Overview

2022 saw the Group once again deliver a strong operational and financial performance. Production was up 6.4%, free cash flows increased to a record $518.9 million and EnQuest net debt was reduced to $717.1 million, its lowest level since 2014. We also undertook a comprehensive refinancing of our debt facilities, extending maturities until 2027. These were significant achievements given the backdrop of volatile markets and several momentous changes in the macro environment, as set out later in this report.

Since we set our strategic priorities of 'deliver, de-lever and grow' at the end of 2018, we have progressed on all fronts. We have delivered strong production performance, controlled costs and exercised capital discipline, focusing on the most value-accretive opportunities. This in turn has allowed us to generate material free cash flows, even when the oil price was depressed during the COVID-19 pandemic, reduce EnQuest net debt by more than

$1.0 billion and deliver an EnQuest net debt to EBITDA ratio of just 0.7x at the end of 2022.

From a growth perspective, our acquisition of the Golden Eagle asset contributed significantly to our cash generation in 2022, while the low-cost acquisitions of material resources at Bressay and Bentley have provided us with future near-field development opportunities that can utilise our heavy oil expertise and differential capability in subsea drilling and tie-backs.

Having established our Infrastructure and New Energy business in 2021, we have now identified and are maturing three discrete and scalable decarbonisation opportunities of carbon capture and storage ('CCS'), electrification, and green hydrogen and derivative production. Our position at the Sullom Voe Terminal ('SVT') provides a strategically advantaged, sustainable and tangible basis upon which to further progress each of these opportunities. At the same time, we have materially reduced our absolute Scope 1 and 2 emissions, with UK Scope 1 and 2 emissions c.43% lower than the 2018 benchmark. This is significantly ahead of the UK's North Sea Transition Deal targets.

We have also cemented our position as a leading decommissioning partner, delivering one of the most productive campaigns seen in the UK North Sea by decommissioning a total of 24 wells at Heather and Thistle last year and being recognised by regulators in both the UK and Malaysia for our decommissioning performance.

Our enhanced business model spans the energy transition spectrum, ensuring the transition is managed in a just and sustainable manner over time. By responsibly managing existing assets, we will continue to provide the production the world needs today while advancing our new energy and decarbonisation opportunity set to support a future lower-carbon energy system, before safely decommissioning those assets. Our business model is underpinned by several complementary, transferable, proven capabilities and provides long-term opportunities for our people.

Market conditions Commodity prices

During 2022, global markets were impacted by a variety of events. Towards the end of 2021 and into early 2022, we saw oil prices recover to pre-pandemic levels as global markets began to reopen and demand for oil products increased. In the lead-up to and following Russia's invasion of Ukraine the oil price quickly escalated, with spot prices peaking at more than $130/bbl in early March. Oil prices remained elevated for the summer, driven in part by measured increases in OPEC+ supply, uncertainty over the impact of sanctions against Russian oil supplies and continued capital discipline across the industry. However, prices began to decline later in the year as several COVID-19 related restrictions remained in place in China, the impact of sanctions played through and global inflation and recessionary pressures mounted. By the end of 2022, oil prices had reverted back towards those seen at the start of the year. Gas prices in Europe and the UK saw significant spikes during the year. Day-Ahead prices peaked at over £5/therm in August, reflecting restricted pipeline gas supplies from Russia and strong competition for liquefied natural gas to meet demand. Close to the end of the year, gas prices reduced significantly as demand softened with milder weather across Europe resulting in better-than-expected storage levels.

Fiscal uncertainty

In May 2022, the UK Government introduced a windfall tax, the EPL, on oil and gas producers. The tax was to take effect immediately at a rate of 25% and was accompanied by investment incentives and a commitment to remove the tax at the point in which oil prices returned to more normal levels or by December 2025, whichever was earlier. Four months later, after a change in prime minister, a mini-budget was announced aiming to protect UK citizens from the 'cost-of-living crisis' and stimulate the UK economy. However, it was widely criticised and led to financial instability, with Sterling weakening appreciably against the US Dollar. In October, almost all of the mini-budget policies were removed, providing some stability to financial markets, with a second change in leadership following shortly afterwards. In the November autumn statement, the new leadership team announced the EPL would be amended and extended, with a higher rate of 35% from 1 January 2023, an end date of March 2028 and the removal of any price floor, which consequently impacted access to capital across the sector.

Inflation

The combination of increasing global activity after lockdown restrictions were eased, supply disruptions and higher food and energy prices saw increases in inflation rates to levels not seen for decades. The Bank of England and other central banks sought to limit inflation by increasing interest rates, with the rate in the UK raised to its highest level in 14 years during December 2022.

Clearly, such volatility imposes significant challenges on any business. However, companies like EnQuest that demonstrate resilience, creativity and adaptability find opportunities in such circumstances. For example, the introduction of the EPL has resulted in a number of industry participants accelerating their shift in focus away from the UK North Sea. Our significant tax loss position and the impact of the EPL on marginal tax rates means if assets were owned by EnQuest their relative value could be a multiple of that in the hands of existing owners. As such, I am confident there will be further M&A opportunities for us to pursue.

Operational performance

EnQuest's average production increased by 6.4% to 47,259 Boepd, primarily driven by a full year's contribution from Golden Eagle following completion of the acquisition on 22 October 2021, along with improved performances at Magnus and PM8/Seligi reflecting the successful execution of extensive well programmes during the year. The well programme at Magnus included the successful completion of the North West Magnus well, which allowed for additional gas export capacity, low-cost perforation work and three wells being returned to service, with simultaneous workover and drilling activities undertaken. The North West Magnus well, which is the longest reservoir section drilled in the North Sea this century at 1,914 metres and represents the longest liner ever run at Magnus, contributed strongly to production of both oil and gas in the fourth quarter. In Malaysia, the infill drilling campaign included the Group's first three horizontal wells at PM8/Seligi, while the four-well workover programme was delivered on budget and ahead of schedule. In addition, we successfully executed a three-well plug and abandonment ('P&A') campaign at PM8/Seligi ahead of schedule and below budget, for which the team were deservedly recognised by the regulator for commitment to safety and the use of new technology. Kraken continued to perform well, delivering top-quartile production efficiency ('PE') of 93% and production at the top end of its guidance range. During the fourth quarter of 2022, Kraken passed the milestone of 60 MMbbls (gross) of oil produced since start-up in mid-2017, and has been one of the Group's best performing assets for a number of years now. While production and drilling performance of the non-operated Golden Eagle asset were below expectations, the asset still contributed strongly to the Group's cash generation and by the end of 2022 had fully paid back the initial cash acquisition costs. That represents a payback period of c.14 months.

During 2022, we produced c.17 MMboe of our year-end 2021 2P reserves base. This reduction in 2P reserves was partially offset by transfers from 2C resources, net of other technical revisions. The Group also changed its reporting of Malaysian 2P reserves to an equity working interest basis to align with peer reporting, having previously adopted an entitlement interest basis. This change added c.11 MMboe to the year-end 2022 balance (see note 7 in the Reserves and Resources table on page 26). As such, 2P reserves at the end of the year were around 190 MMboe, down from c.194 MMboe reported at the end of 2021 (c.205 MMboe on a comparative working interest basis). We continue to have material 2C resources of around 393 MMboe, with Bressay and Bentley each holding more than 100 MMboe of net 2C resources, while Magnus and Kraken in the UK and PM8/Seligi and PM409 offshore Malaysia also hold material 2C resources.

Our Infrastructure and New Energy business has moved forward at pace this year. We have developed three credible and scalable new energy and decarbonisation opportunities, built on the unique and tangible strategic advantages of SVT, while continuing to deliver top-quartile operational and HSE performance at the terminal for existing users of the site. Securing an exclusivity agreement with the Shetland Islands Council provides us with a platform from which to connect potential strategic partners and piece together the component parts of each of the opportunities we have. We are hopeful of success in the next stage of the process as we await the outcome of our application for offshore CCS licences.

2022 was a year in which our UK team demonstrated, and were recognised for, decommissioning excellence. Our extensive UK decommissioning work programme saw the successful execution of 24 well P&As across the Heather and Thistle fields and we remain on track for our targeted disembarkation dates at both platforms, with topside removal work planned for around the middle of the decade. We have awarded the heavy lift contract for the Heather topsides and are at an advanced stage on the Thistle topside removal contract award.

Having only been established in 2020, it was pleasing to see the decommissioning team recognised for excellence by Offshore Energies UK for its work, executed in 2021, on the Northern Producer off-station project at the Dons field.

Financial performance

The Group's adjusted EBITDA and statutory gross profit increased by 31.8% to $979.1 million and 82.3% to $652.9 million, respectively, reflecting higher realised oil prices and production. Operating costs for the year of $396.5 million were higher than 2021, including the full-year impact of Golden Eagle, higher market price driven costs and lower lease charter credits, reflecting continued high uptime at Kraken. Unit operating costs increased to $22.7/Boe, primarily reflecting the impacts on costs noted above. Cash generated by operations increased to $1,026.1 million, up by 35.6% compared to 2021, with free cash flow generation of

$518.9 million.

This strong financial and operating performance during the year underpinned delivery of our comprehensive refinancing of each of our three debt facilities in what were extremely challenged financial markets.

With the introduction of the EPL during the year, the Group assessed the carrying value of its assets as at 31 December 2022. The net impact of the EPL, changes in asset profiles and higher forecast oil prices resulted in the Group recording a pre-tax non-cash impairment charge of $81.0 million. In January, the Group's RBL redetermination was undertaken and included the increase in EPL rate to 35%, its extension of duration until 2028 and removal of the windfall tax price floor. This redetermination has resulted in a reduction in the funds available in the RBL facility from $500.0 million to c.$339.0 million. The Group has made repayments totaling $118.0 million in the first quarter of 2023, ensuring it stays ahead of the revised capacity limits.

Environmental, Social and Governance

The health, safety and wellbeing of our employees remains our top priority. In 2022, we achieved an upper quartile Lost Time Incident ('LTI') frequency1rate. However, there was an increase in the number of LTIs from 2021 for which intervention was undertaken, emphasising increased focus on situational awareness and dynamic risk assessment. During 2022, our team developed a fully integrated HSEA Continuous Improvement Plan ('CIP') to drive enhanced performance in 2023 and beyond. This CIP is fully aligned to the Group's HSEA Policy and has been implemented across the North Sea and Malaysia operations.

As outlined earlier, we have made excellent progress in reducing absolute Scope 1 and 2 emissions during the year with the Group's CO₂ equivalent emissions reduced by c.23% since 2020 and the UK's emissions down by c.43% since 2018, reflecting lower flaring and lower fuel gas and diesel usage. This progress is significantly ahead of the Group's targeted reductions and those set by the UK Government's North Sea Transition Deal. At the same time, we continue to optimise sales of Kraken cargoes directly to the shipping fuel market, avoiding emissions related to refining and helping reduce sulphur emissions.

This year saw a number of changes to our Board, with Martin Houston, Jonathan Swinney and Philip Holland stepping down, to be succeeded by Gareth Penny (Chairman), Salman Malik (Chief Financial Officer) and Rani Koya (Non-Executive Director), respectively. I would like to thank Martin, Jonathan and Philip for their contributions, and I look forward to working with Gareth, Salman and Rani as we execute on our integrated energy strategy. Following these changes, the EnQuest Board has 33% female representation, which shows good progress towards the FTSE Women Leaders Review target of 40% and remains ahead of the Parker Review target with respect to minority ethnic representation, with four minority ethnic board members.

1 Lost Time Incident frequency represents the number of incidents per million exposure hours worked (based on 12 hours for offshore and eight hours for onshore)

2023 performance and outlook

Production performance to the end of March was around 47,800 Boepd. Our full-year net production guidance of between 42,000 and 46,000 Boepd includes the impacts from drilling campaigns at Magnus and Golden Eagle and required maintenance activities at Kraken, Magnus and the Greater Kittiwake Area.

Operating costs are expected to be approximately $425.0 million, while capital expenditure is expected to be around $160.0 million, with decommissioning expenditure expected to total approximately $60.0 million.

Longer-term development

Over the last few years, we have enhanced our strategy and business model with the aim of meeting society's energy needs of today and tomorrow. The Upstream business is focused on responsibly optimising production to drive cash generation for further deleveraging, selective organic and inorganic investments and returns to shareholders. Our Infrastructure and New Energy business is assessing repurposing opportunities which leverage existing infrastructure to build scalable businesses in each of CCS, electrification and hydrogen production, supporting decarbonisation at levels which could take the Company beyond net zero emissions. In Decommissioning, we manage end of field life and post-cessation of production operations to deliver safe and efficient execution of decommissioning work programmes in a responsible manner.

This collective offering, alongside our advantaged tax position in the UK, enhances our M&A credentials as a responsible owner and operator of existing assets and infrastructure as we transition to a lower-carbon energy system, offering our people long-term opportunities.

We look forward to delivering on our strategic aims as we transition.

Operating review

Upstream operations

2022 Group performance summary

Production of 47,259 Boepd reflected improved performances at Magnus and at PM8/Seligi, continued strong performance at Kraken and the impact of a full year of contribution from Golden Eagle; this was partially offset by the expected natural declines across the portfolio. The Group executed significant well programmes during 2022 following the necessary pause in drilling during the low commodity price environments experienced during 2020 and 2021.

Magnus

2022 performance summary

2022 production of 12,641 Boepd was 6.5% higher than the 2021 figure of 11,870 Boepd, with production efficiency for the year at 66%. With simultaneous workover and drilling activities undertaken, a key success at Magnus was the completion of the North West Magnus well and its associated gas production, while perforation work at a second target well was successful in adding incremental volumes at significantly lower cost than infill drilling. The North West Magnus well, which is the longest reservoir section drilled in the North Sea this century at 1,914 metres and represents the longest liner ever run at Magnus, contributed strongly to production of both oil and gas in the fourth quarter. In remedying well integrity issues encountered during the first half of the year, the Group's well intervention programme returned two wells to service in the first half of 2022, with production from a third producer reinstated during the fourth quarter.

The planned annual shutdown was completed during the third quarter and all major scopes were executed, with the primary focus on compressor maintenance activities. Following generator refurbishment work, the asset power generation unit has been performing reliably since February 2022, raising confidence that previous topside issues have been largely mitigated and enabling Magnus to facilitate consistent gas supply to the UK.

2023 outlook

A shutdown of around three weeks is planned in the third quarter to complete scheduled safety-critical activities, while further asset integrity maintenance and plant improvement opportunities will continue to be assessed and implemented throughout the year in order to reduce platform vulnerability. In addition, the Group plans to implement a variety of permanent solution repair methods to wells impacted by the P-seal design, which has caused well integrity issues in recent years.

It is anticipated that three wells will be drilled in 2023, including a water injector to provide pressure support to the North West Magnus well, with the expectation that Magnus production will be higher than 2022. With 2C resources of c.35 MMboe, Magnus offers the Group significant low-cost, quick payback drilling opportunities in the medium term.

Kraken

2022 performance summary

Average gross production was at the top end of the Group's guidance range at 26,091 Boepd gross (18,394 Boepd net). Overall subsurface and well performance was good with aggregate water cut evolution remaining in line with expectations. The Floating, Production, Storage and Offloading ('FPSO') vessel continued to perform well throughout the year, with top-quartile production and water injection efficiency of 93%. The planned shutdown saw all key scopes completed ahead of schedule, having been optimised to facilitate single train processing train operations for one week of the two-week programme of activities.

During the fourth quarter of 2022, Kraken production reached the milestone of over 60 million barrels (gross) produced since inception.

The Group continues to optimise Kraken cargo sales into the shipping fuel market, with Kraken oil a key component of IMO 2020 compliant low-sulphur fuel oil. While the Group has seen varied pricing within this market, 2022 sales again delivered a premium versus Brent pricing and avoided refining- related emissions.

2023 outlook

No shutdown is planned during 2023 but it is expected that two separate ten-day periods of single processing train operations will be undertaken in order to execute safety-critical maintenance work.

Near-field drilling and subsea tie-back opportunities continue to be assessed, with interpretation of 3D seismic data ongoing. In light of the direct impact of the EPL on the Group's available cash flow and the indirect contribution to underlying inflationary pressures through incentivisation of industry-wide investment within a defined timeline, the Group has delayed its plans to progress the Kraken drilling programme. With c.33 Mmboe of 2C resources, there remains significant opportunity in terms of main field side-track drilling opportunities, along with further drilling within the Pembroke and Maureen sands, but the Group has delayed the decision to sanction investment until 2024 at the earliest. As such, Kraken production will be subject to natural decline in the coming years.

Golden Eagle

2022 performance summary

2022 net production was 6,323 Boepd. Production efficiency remained strong at around 95% although production rates were lower than forecast. EnQuest continues to work with the operator and the joint venture partners to identify opportunities to maximise rates.

The planned two-well infill drilling campaign is ongoing, but delayed. The first wellbore, having failed to locate reservoir-quality sands, was plugged and the well was side-tracked to the second target. Adverse weather conditions have resulted in expected first production from this well being deferred into the second quarter of 2023.

2023 outlook

Further to completion of the delayed 2022 drilling campaign, a platform well programme is expected to commence later in the year, subject to joint venture approval.

The operator has scheduled a shutdown of around two weeks in the summer of 2023, with subsequent major shutdowns expected to be required every two to three years.

Other Upstream assets

2022 performance summary

Production in 2022 averaged 3,443 Boepd, largely in line with expectations and reflecting strong uptime of 87% at the Greater Kittiwake Area. At Alba, performance continued largely in line with the Group's expectations.

In response to adverse changes to the EPL, several operators have begun to reconsider their capital programmes in the UK. In late 2022, EnQuest increased its equity interest in Bressay to 100%, following the withdrawal of Equinor and Harbour Energy.

2023 outlook

At GKA, a three-week shutdown is planned during the second quarter, as well as a short shutdown of related infrastructure.

At Alba, the partners expect to execute a well workover and a two infill well drilling programme during 2023, the first of which is due to deliver first oil during the third quarter.

At Bressay, EnQuest is actively exploring farm-down opportunities while continuing to progress development planning of the asset. EnQuest aims to utilise its expertise in heavy oil developments to access hydrocarbons at Bressay and Bentley, with each field having more than 100 Mmboe of 2C resources.

Malaysia operations

2022 performance summary

Average production of 6,458 Boepd was 28% higher than 2021. Production was boosted by a successful four-well workover campaign and the delivery of the Group's first three horizontal wells at PM8/Seligi being brought onstream, partially offset by natural declines and compressor downtime.

A three-well plug and abandonment ('P&A') campaign at PM8/Seligi was executed ahead of schedule, with costs delivered 30% below budget. In recognition of the success of the 2022 well workover and P&A campaign, EnQuest received three awards from Petronas for commitment to safety and use of new technology.

2023 outlook

A three-week shutdown at PM8/Seligi to undertake asset integrity and maintenance activities is planned for the summer, which will help to improve reliability and efficiency at the field. Well P&A work will also continue, primarily funded by a centralised investment fund to which EnQuest contributes, with six well abandonments planned for 2023.

EnQuest has significant 2P reserves and 2C resources of c.31 Mmboe and c.80 Mmboe, respectively, and continues to assess a potential 2023 drilling programme in Malaysia, with future multi-well annual drilling programmes planned.

The Group continues to work with the regulator to assess the opportunity to develop the additional gas resource at PM8/Seligi to meet forecast Malaysian demand.

At PM409, the Group plans to drill an exploration well in the middle of the year, in line with the work programme commitment.

Infrastructure and New Energy

Infrastructure

Operational excellence

Throughout 2022, the Group continued to deliver top-quartile operational and HSE performance at the Sullom Voe Terminal ('SVT'). SVT delivered 100% continuous uptime for East of Shetland and West of Shetland operations, while executing a number of operational risk reduction projects, including major inspections and replacing sections of pipeline.

Preparing for the future

The Group is now developing plans for a multi-year programme of projects which will right-size the terminal facilities for expected future throughput and prepare the way for the next phase of SVToperations, including new energy and decarbonisation activities.This programme of work will ensure EnQuest reduces the emissions footprint of the site and provides ongoing cost-effective and efficient support to East of Shetland and West of Shetland operators. The enhanced investment allowance associated with decarbonisation expenditure under the UK EPL is expected to support the delivery of these programmes.

New energy

Well positioned to deliver decarbonisation

EnQuest's new energy strategy is anchored in its unique infrastructure position and strong engineering and subsurface capability. The terminal site offers several unique competitive advantages, including a 1,000-acre industrial site with access to existing oil and gas pipeline infrastructure, a

deep-water port and jetties, the highest wind capacity factor across Europe, and a highly skilled workforce and local supply chain. The Group aims to deliver on its ambitions to deliver decarbonisation opportunities at scale with strategic partners in a capital-light manner.

The first step in the process requires the existing site to be repurposed. A key enabler in this regard was the Group's success in securing exclusivity from the Shetland Islands Council to progress its proposed new energy opportunities on the Sullom Voe site in March 2022.

This provides EnQuest with a strong position from which to hold discussions with other potential strategic partners to piece together the component parts of each of the three key opportunities the Group has identified.

Key projects

Carbon Capture and Storage ('CCS')

The availability of a natural deep-water port with four jetties, as well as a pipeline network linked to several well-understood offshore reservoirs, presents an exceptional opportunity to repurpose existing infrastructure and enable the import and permanent storage of material quantities of CO₂ from isolated emitters in the UK, Europe or further afield.

EnQuest has applied for two CCS licences for East of Shetland reservoirs as part of the North Sea Transition Authority ('NSTA') licensing round and has conducted initial phases of feasibility and economic screening work in respect of this carbon storage concept. These studies indicate the capability of the existing infrastructure, including the EnQuest-operated East of Shetland pipeline system, and storage sites to support a project that could store up to 10 million tonnes of CO₂ per annum, with initial studies suggesting the presence of total storage potential in excess of 500 million tonnes.

This quantity of potential carbon storage represents a multiple of the Group's existing direct emissions.

Electrification

EnQuest is assessing the potential to leverage its existing infrastructure and subsea projects expertise to facilitate the electrification of nearby offshore oil and gas assets and planned developments by way of a grid connection supplemented by renewable power. EnQuest believes that this offers a robust and economically viable option to facilitate offshore electrification and would lead to significant emission reductions for platforms which are expected to operate into the 2050s. EnQuest remains in discussions with West of Shetland field owners, some of whom could take advantage of the EPL decarbonisation allowance available for this investment.

In addition, the Group is also currently assessing onshore wind potential and a new power solution for SVT, which has the potential to significantly reduce the Group's carbon footprint.

Hydrogen

EnQuest is exploring the potential for harnessing the advantaged natural wind resource around Shetland for the production of green hydrogen and derivatives at export scale to provide a low-carbon alternative fuel which could help to decarbonise a number of industries, with ambitions to produce around one million tonnes of green hydrogen annually.

Decommissioning

Performance Summary

Within EnQuest's decommissioning directorate, 2022 was a year of demonstrating capability and public recognition of decommissioning excellence as EnQuest delivered one of the most productive decommissioning campaigns seen in the UK North Sea.

Well decommissioning

At both the Heather and Thistle fields, the extensive programme of well plug and abandonment ('P&A') continued apace. Thistle successfully abandoned 13 wells while Heather executed 11 wells, with partial completion of a further four wells by year end. In addition, five wells have been plugged and abandoned during the first quarter of 2023. The Heather project team is looking for further opportunities to perform P&A activities without the use of the main platform rig, which will further underpin its expectation that the target to disembark the platform in the fourth quarter of 2024 will be met. At Thistle, the team aim to complete disembarkation by the end of the third quarter of 2025. Both assets remain on track to meet their post-cessation of production well P&A targets of 39 wells at Heather by mid-2024, and 41 wells at Thistle by the end of the fourth quarter of 2024.

EnQuest is also planning the P&A of 33 subsea wells at the Alma/Galia, Dons and Broom fields and aims to be execution-ready during the second quarter of 2024. The EnQuest team is working on the basis that subsea decommissioning activities can be optimised by utilising a portfolio approach across the fields.

Heavy Lift Awards

The Heather and Thistle project teams successfully secured partnership funding for the next phase of their decommissioning programmes, with both assets remaining focused on preparing their respective topside modules for removal. To this end, Heather has secured the Allseas Pioneering Spirit to execute the heavy lift of the platform topsides, from 2025 onwards. Advanced preparatory work is ongoing, with the project team working closely with Allseas to ensure full understanding and integration of the necessary work-scopes in advance of platform disembarkation. In addition, EnQuest has awarded the contract for the Heather jacket removal to Saipem from 2026 onwards, with the early placing of this contract securing favourable market rates and allowing for the interface with topsides and conductor removal scopes to be optimised.

The process to award the contract for Thistle topsides removal is nearing completion and is expected to be announced in the coming months. The lift itself, which will take place from 2026 onwards, will see all 32 modules of the Thistle platform moved onto the heavy lift vessel and returned to shore in four separate voyages. Throughout 2023 and 2024, the project team will be focused on the engineering required to prepare for the heavy lift as well as opportunities to reduce schedule and beat cost and delivery targets.

Given increased competition in the heavy lift vessel market, with the evolution of several large-scale renewable projects being sanctioned by the governments of European countries, EnQuest will manage the execution of the heavy lift scopes within multi-year windows in order to retain flexibility and mitigate availability concern.

Decommissioning excellence

In recognition of the Group's top-quartile project delivery, EnQuest secured the Offshore Energies UK ('OEUK') Award for Excellence in Decommissioning for its work on the Northern Producer off-station project at the Dons fields.

The prompt and efficient removal and decommissioning of the Northern Producer Floating Production Facility ('FPF') at the field enabled post-cessation of production operating expenditure to be minimised and, with the field being gas deficient, facilitated a significant reduction in diesel consumption and subsequent carbon emissions.

Financial review

All figures quoted are in US Dollars and relate to Business performance unless otherwise stated.

Introduction

Shortly after becoming Chief Financial Officer, Salman Malik set out his financial priorities for the Company and we are pleased with the progress we made during 2022. Strong free cash flows of $518.9 million in 2022 enabled a 41.3% reduction in EnQuest net debt, which was reduced by $504.9 million to $717.1 million (2021: $1,222.0 million). This rapid deleveraging has helped the Group make excellent progress towards its EnQuest net debt to adjusted EBITDA leverage target of 0.5x. The Group's debt facilities have also been comprehensively refinanced during 2022, reducing the level of gross borrowings and extending maturities by five years to 2027. This was a significant achievement given the volatile backdrop in financial markets.

Lower than planned spend has been driven by operational excellence, strong financial discipline and a focus on near-term value-accretive activities, including extensive well programmes at Magnus and PM8/Seligi. During 2022, EnQuest delivered one of the most productive well decommissioning campaigns seen in the UK North Sea and good progress was made in advancing the Group's new energy and decarbonisation opportunities in a capital- light manner.

The Group retains a significant tax loss position which provides it with a strategic advantage in the UK North Sea, enhancing the relative value of assets in EnQuest's hands when compared to other tax paying participants. Following the introduction and subsequent changes to the UK Energy Profits Levy ('EPL'), this relative value advantage has increased, and the Group is confident it will be able to continue its track record of value-accretive acquisitions as other North Sea participants look to exit the basin. The incentives associated with decarbonisation expenditure could also help underpin elements of the Group's plans to repurpose the Sullom Voe Terminal into one of the largest new energy hubs in Europe. However, the EPL has resulted in a reduced reserve based lending ('RBL') facility resulting in the Group optimising its capital programme, focussing on quick-payback investments. We continue to prioritise continued deleveraging through 2023, with $118.0 million of the RBL facility repaid in the first quarter, with shareholder returns expected to follow in the future.

Performance overview

Production on a working interest basis increased by 6.4% to 47,259 Boepd, compared to 44,415 Boepd in 2021 driven by a full year's contribution from Golden Eagle and improved performances at Magnus and PM8/Seligi, reflecting successful well programmes. Production at Kraken was lower year-on-year but remained at the top end of market guidance.

Revenue for 2022 was $1,839.1 million, 39.3% higher than in 2021 ($1,320.3 million), primarily reflecting higher realised prices and higher production. The Group's commodity hedge programme resulted in realised losses of $203.7 million in 2022 (2021: losses of $67.7 million), which reflected the timing at which the hedges were entered into and the increase in market prices during the year, particularly following the Russian invasion of Ukraine. See note

19 for further information on the Group's hedging position.

The Group's operating expenditures of $396.5 million were 23.5% higher than in 2021 ($321.0 million). This was primarily due to higher production costs, including the full-year impact of Golden Eagle, higher fuel and emission trading allowance costs due to higher market prices and lower lease charter credits, reflecting high uptime at Kraken driven by the continued strong performance of the FPSO. This was partially offset by a weakening of the Sterling to US Dollar exchange rate, with c.70% of the Group's costs denominated in Sterling. Unit operating costs (excluding hedging) increased to

$22.7/Boe (2021: $20.5/Boe).

Other costs of operations of $487.8 million were significantly higher than in 2021 ($211.5 million), predominantly as a result of higher Magnus-related third-party gas purchases of $452.8 million (2021: $199.6 million) due to the increase in associated market prices.

With the Group reversing the previous year's net overlift position, a credit relating to the Group's lifting position and inventory of $15.6 million was recognised (2021: charge of $62.3 million).

Adjusted EBITDA for 2022 was $979.1 million, up 31.8% compared to 2021 ($742.9 million), primarily as a result of higher revenue partially offset by higher costs. EnQuest net debt to adjusted EBITDA ratio at 31 December 2022 was 0.7x, down more than 50% from 1.6x at 31 December 2021.

	2022 $ million	2021 $ million
Profit/(loss) from operations before tax and finance income/(costs)	709.2	443.2
Depletion and depreciation	333.2	313.1
Change in provision	(42.8)	(13.1)
Change in well inventories	0.8	0.1
Net foreign exchange (gain)/loss	(21.3)	(0.4)
Adjusted EBITDA	979.1	742.9

EnQuest net debt decreased by $504.9 million to $717.1 million at 31 December 2022 (31 December 2021: $1,222.0 million). EnQuest net debt includes

$25.1 million of payment in kind ('PIK') interest that has been capitalised to the principal of the bond facilities pursuant to the terms of the Group's November 2016 refinancing (31 December 2021: $225.0 million) (see note 18 for further details).

EnQuest net debt/(cash) 1

	31 December	31 December
	2022 $ million	2021 $ million
Bonds	600.7	1,083.8
RBL	400.0	415.0
SVT working capital facility	12.3	9.9
Vendor loan facility	5.7	-
Cash and cash equivalents	(301.6)	(286.7)
EnQuest net debt	717.1	1,222.0
Note: 1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 63

During 2022, strong free cash flows enabled the Group to make early voluntary repayments on its previous RBL facility, resulting in the balance being repaid in full. In October, the facility was refinanced with commitments of $500.0 million.

In April 2022, the Group partially refinanced its 7% Sterling retail bond ('7.00% retail bond') through an exchange and open offer. The principal of the new 9% Sterling retail bond ('9.00% retail bond') raised was £133.3 million, made up of £79.3 million of exchanges from the 7.00% retail bond and £54.0 million from new bond holders.

In July and August, the Group bought back and cancelled $34.9 million of its 2023 7.00% high yield bond, leaving $792.3 million outstanding. This was subsequently repaid in full in October 2022, along with outstanding interest of $1.5 million due at the time of repayment, utilising $400.0 million of drawdowns from the Group's refinanced RBL, operating cash flows of $97.5 million and the net proceeds from the issue of a new US Dollar high yield bond ('11.625% high yield bond') of $296.3 million.

See note 18 for further information on the Group's loans and borrowings.

In July 2022, the EPL was enacted in the UK which applied an additional tax of 25% on the profits earned by oil and gas companies from the production of oil and gas on the United Kingdom Continental Shelf. In November 2022, the EPL percentage was increased to 35% from 1 January 2023 and the end date was extended from 31 December 2025 to 31 March 2028. As such, the Group has estimated a current tax charge of $72.1 million (2021: $nil) associated with the EPL for 2022. The Group has also recognised a total net deferred tax charge of $153.7 million at 31 December 2022 (31 December 2021: $nil), with a $25.2 million credit recognised in Business performance and $178.9 million charge in Remeasurements and exceptional items.

The Group has recognised UK North Sea corporate tax losses at the end of 2022 of $2,497.7 million (2021: $3,011.0 million). Unrecognised tax losses are disclosed in note 7(d) on page 41. In the current environment, no significant corporation tax or supplementary charge is expected to be paid on UK operational activities for the foreseeable future. The Group paid its first instalment associated with the EPL in December 2022 and will continue to make EPL payments for the duration of the levy. The Group also paid cash corporate income tax on the Malaysian assets, which will continue throughout the life of the Production Sharing Contract.

Income statement Revenue

Market prices for crude oil and gas in 2022 were significantly higher than in 2021 driven by increasing global demand as COVID-19 restrictions began easing, combined with supply concerns brought about by years of underinvestment and amplified by the Russian invasion of Ukraine and the associated subsequent sanctions imposed on Russia. The Group's average realised oil price excluding the impact of hedging was $102.6/bbl, 40.5% higher than in 2021 ($73.0/bbl). Revenue is predominantly derived from crude oil sales, which totalled $1,517.7 million, 33.2% higher than in 2021 ($1,139.2 million), reflecting the significantly higher oil prices and the contribution from Golden Eagle. Revenue from the sale of condensate and gas, primarily in relation to the onward sale of third-party gas purchases not required for injection activities at Magnus, was $514.2 million (2021: $244.1 million), reflecting significantly higher prices. Tariffs and other income generated $11.0 million (2021: $4.7 million). The Group's commodity hedges and other oil derivatives contributed $203.7 million of realised losses (2021: losses of $67.7 million) as a result of the timing of entering into the hedges. The Group's average realised oil price including the impact of hedging was $88.9/bbl in 2022, 29.6% higher than in 2021 ($68.6/bbl).

Cost of sales1
	2022 $ million	2021 $ million
Production costs	347.8	292.3
Tariff and transportation expenses	43.3	39.4
Realised loss/(gain) on derivatives related to operating costs	5.4	(10.7)
Operating costs	396.5	321.0
(Credit)/charge relating to the Group's lifting position and inventory	(15.6)	62.3
Depletion of oil and gas assets	327.0	305.6
Other cost of operations	487.9	211.5
Cost of sales	1,195.8	900.4
Unit operating cost²	$/Boe	$/Boe
- Production costs	20.2	18.1
- Tariff and transportation expenses	2.5	2.4
Average unit operating cost	22.7	20.5
Notes: 1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 63 2 Calculated on a working interest basis

Cost of sales were $1,195.8 million for the year ended 31 December 2022, 32.8% higher than in 2021 ($900.4 million).

Operating costs increased by $75.5 million, primarily reflecting higher production costs, including the full-year impact of Golden Eagle, higher fuel and emission trading allowance costs due to higher market prices and lower lease charter credits, reflecting high uptime at Kraken driven by the continued strong performance of the FPSO. This was partially offset by a weakening of the Sterling to US Dollar exchange rate with c.70% of the Group's costs denominated in Sterling. Unit operating costs (excluding hedging) increased by 10.7% to $22.7/Boe (2021: $20.5/Boe), reflecting higher operating costs. Unit operating costs including hedging were $23.0/Boe (2021: $19.8/Boe).

$327.0 million was 7% higher than in 2021 ($305.6 million), mainly reflecting the impact of Golden Eagle.

Other cost of operations of $487.9 million were materially higher than in 2021 ($211.5 million), principally as a result of higher Magnus-related third-party gas purchases of $452.8 million (2021: $199.6 million) following the increase in associated market prices.

Other income and expenses

Net other income of $73.4 million (2021: net other income of $23.7 million) is predominantly due to a net decrease in the decommissioning provision of fully impaired non-producing assets of $42.8 million (including the Thistle decommissioning linked liability) due to higher discount rates and a favourable movement in the Sterling to US Dollar balance sheet exchange rate, which has also resulted in further favourable foreign exchange credits recognised of $21.3 million. Also included within other expenses are costs associated with Infrastructure and New Energy of $1.2 million.

Finance costs

Finance costs of $176.2 million were 4.0% higher than in 2021 ($169.5 million). This increase was primarily driven by fees associated with the retail bond transaction and the amortisation of arrangement fees of $35.3 million associated with the Group's refinancing activities (2021: $13.6 million associated with the 2021 RBL facility refinancing). This increase has been partially offset by the reduction of $5.3 million in interest charges associated with the Group's loans (2022: $14.9 million; 2021: $20.2 million) and a $6.8 million decrease in bond interest (2022: $63.3 million; 2021: $69.1 million). Other finance costs included lease liability interest of $39.2 million (2021: $45.4 million), $17.8 million on unwinding of discount on decommissioning and other provisions (2021:

$16.9 million), and other financial expenses of $6.8 million (2021: $4.3 million), primarily being the cost for surety bonds to provide security for decommissioning liabilities.

Taxation

The tax charge for 2022 of $322.4 million (2021: $53.7 million tax charge), excluding remeasurements and exceptional items, reflects the tax impact on the Group's increased profit before tax and the enactment of the UK EPL. Ring Fence Expenditure Supplement ('RFES') on UK activities, which would historically have provided an offset to the UK tax charge, ceased to be available to claim from the end of 2021.

Remeasurements and exceptional items

Remeasurements and exceptional items resulting in a post-tax net loss of $253.6 million have been disclosed separately for the year ended 31 December 2022 (2021: post-tax gain of $156.7 million).

Revenue included unrealised gains of $14.5 million in respect of the mark-to-market movement on the Group's commodity contracts, primarily reflecting the recycling of 2021 unrealised hedge losses into Business performance during 2022 (2021: unrealised losses of $54.5 million).

Cost of sales included unrealised losses of $4.9 million relating to the mark-to-market movement on the Group's foreign exchange contracts (2021: unrealised gains of $0.5 million).

A non-cash net impairment charge of $81.0 million (2021: $39.7 million reversal) on the Group's oil and gas assets arose from the impact on future cash flows following the introduction of the EPL, updated asset profiles and a higher discount rate, partially offset by higher forecast oil prices.

Other income includes $6.6 million of insurance proceeds received in respect of the Malaysia riser repairs (2021: $9.0 million). Other expense includes a

$233.6 million charge in relation to the fair value recalculation of the Magnus contingent consideration, reflecting a forecast increase in Magnus future cash flows due to higher forecast oil prices and asset profile and cost assumption changes (2021: $140.1 million gain).

Other finance costs mainly relate to the unwinding of discount on contingent consideration from the acquisition of Magnus and associated infrastructure of $36.4 million (2021: $58.4 million). Other finance income reflects the gain recognised on buy back and cancellation of $34.9 million

of the Group's 7.00% high yield bond.

A net tax credit of $78.0 million (2021: credit of $78.2 million) has been presented as exceptional, representing the tax effect on the items above and the non-cash recognition of undiscounted deferred tax assets of $127.0 million given the net effect of the Group's higher long-term oil price assumptions and changes in asset profiles, partially offset by the initial recognition of the deferred tax liability associated with the EPL of $178.3 million. EnQuest has recognised UK North Sea corporate tax losses of $2,497.7 million at 31 December 2022, with unrecognised tax losses disclosed in note 7(d) on page 41.

IFRS results

The Group's results on an IFRS basis are shown on the Group income statement as 'Reported in the year', being the sum of its Business performance results and Remeasurements and exceptional items, both of which are explained above.

IFRS revenue reflects the Group's Business performance revenue, but it is adjusted for the impact of unrealised movements on derivative commodity contracts. Business performance cost of sales is similarly adjusted for the impact of unrealised movements on derivative contracts. Taking account of these items, and the other exceptional items included within the Group income statement, which are principally related to impairment charges and the change in fair value of contingent consideration payable, the Group's IFRS profit from operations before tax and finance costs was $411.9 million (2021: profit of $580.0 million), IFRS profit before tax was $203.2 million (2021: profit of $352.4 million), and IFRS loss after tax was $41.2 million (2021: profit of $377.0 million). This IFRS loss after tax was primarily driven by the initial recognition of deferred tax liability following the introduction of the EPL.

Earnings per share

The Group's Business performance basic earnings per share was 11.4 cents (2021: 12.7 cents) and diluted earnings per share was 11.2 cents (2021:

12.5 cents).

The Group's reported basic loss per share was 2.2 cents (2021: earnings of 21.7 cents) and reported diluted loss per share was 2.2 cents (2021: diluted earnings of 21.4 cents).

Cash flow and liquidity

EnQuest net debt at 31 December 2022 amounted to $717.1 million, including PIK of $25.1 million, compared with EnQuest net debt of $1,222.0 million at 31 December 2021, including PIK of $225.5 million. The movement in EnQuest net debt was as follows:

	$ million
EnQuest net debt 1 January 2022	(1,222.0)
Net cash flows from operating activities	931.6
Cash capital expenditure	(115.8)
Magnus profit share payments	(46.0)
Finance lease payments	(148.0)
Net interest and finance costs paid	(101.6)
Other movements, primarily net foreign exchange on cash and debt	(15.3)
EnQuest net debt 31 December 2022 ¹	(717.1)
Note: 1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 63

The Group's reported net cash flows from operating activities for the year ended 31 December 2022 were $931.6 million, up 38.2% compared to 2021 ($674.1 million), primarily driven by materially higher revenue.

Cash outflow on capital expenditure is set out in the table below:

	Year ended 31 December	Year ended 31 December
	2022	2021
	$ million	$ million
North Sea	85.5	35.9
Malaysia	26.5	14.8
Exploration and evaluation	3.8	1.1
	115.8	51.8

Cash capital expenditure in 2022 primarily related to Magnus and PM8/Seligi well campaigns.

Balance sheet

The Group's total asset value has decreased by $341.3 million to $4,024.3 million at 31 December 2022 (2021: $4,365.6 million), predominantly due to depletion and impairment charges on the oil and gas assets. Net current liabilities have increased to $435.3 million as at 31 December 2022 (2021:

$333.1 million).

Property, plant and equipment ('PP&E')

PP&E has decreased by $345.0 million to $2,477.0 million at 31 December 2022 from $2,822.0 million at 31 December 2021 (see note 10). This decrease includes depletion and depreciation charges of $333.2 million, non-cash net impairment charges of $81.0 million and a net decrease of $75.9 million for changes in estimates for decommissioning and other provisions, partially offset by other capital additions to PP&E of $146.7 million.

The PP&E capital additions during the year are set out in the table below:

	$ million
North Sea	107.7
Malaysia	39.0
	146.7

Trade and other receivables

Trade and other receivables decreased by $19.7 million to $276.4 million at 31 December 2022 (2021: $296.1 million). The decrease is driven by the timing of cargoes and associated receipts lifted in December each year.

Cash and EnQuest net debt

The Group had $301.6 million of cash and cash equivalents at 31 December 2022 and $717.1 million of EnQuest net debt (2021: $286.7 million and

$1,222.0 million, respectively).

EnQuest net debt comprises the following liabilities:

• $134.5 million principal outstanding on the 7.00% retail bond, including PIK of $25.1 million (2021: $256.2 million and $47.9 million, respectively);

• $161.2 million principal outstanding on the 9.00% retail bond;

• $nil principal outstanding on the 7.00% high yield bond (2021: principal $827.2 million including PIK of $177.2 million);

• $305.0 million principal outstanding on the 11.625% high yield bond;

• $400.0 million drawn down on the refinanced RBL (2021: $415.0 million);

• $12.3 million relating to the SVT Working Capital Facility (2021: $9.9 million); and

• $5.7 million relating to a Vendor Loan Facility (2021: $nil).

Provisions

The Group's decommissioning provision decreased by $144.1 million to $691.6 million at 31 December 2022 (2021: $835.7 million). The movement is due to a reduction in estimates of $115.5 million, reflecting an increase in discount rate (see notes 2 and 23 and a favourable movement in the Sterling to US Dollar balance sheet exchange rate, utilisation of $48.5 million for decommissioning carried out in the year, partially offset by $17.0 million unwinding of discount and additions of $2.8 million.

Other provisions, including the Thistle decommissioning provision, decreased by $13.1 million in 2022 to $46.1 million (2021: $59.2 million). The Thistle decommissioning provision of $32.7 million (2021: $43.9 million) is in relation to EnQuest's obligation to make payments to bp by reference to 7.5% of bp's decommissioning costs of the Thistle and Deveron fields.

Contingent consideration

The contingent consideration related to the Magnus acquisition increased by $222.1 million. In 2022, EnQuest paid $46.0 million to bp under the profit sharing mechanism (2021: $74.7 million, including $73.7 million of accelerated vendor loan repayment and $1.0 million under the profit sharing mechanism). A change in fair value estimate charge of $233.6 million (2021: $140.1 million credit) and finance costs of $34.5 million (2021: $58.4 million) were recognised in the year.

The contingent consideration related to the Golden Eagle acquisition in 2021 increased by $3.2 million to $48.3 million (2021: $45.2 million). The increase represents unwind of discount and is disclosed in finance costs.

Income tax

The Group had a net income tax payable of $37.7 million (2021: $3.6 million payable) primarily related to the remaining EPL payment due in relation to the 2022 charge.

Deferred tax

The Group's net deferred tax asset has decreased from $699.6 million at 31 December 2021 to $539.5 million at 31 December 2022. This is primarily driven by the initial recognition of the net deferred tax liability of $178.3 million associated with the EPL and utilisation of tax losses, partially offset by the non-cash recognition of $127.0 million of undiscounted deferred tax assets given the Group's higher long-term oil price assumptions and changes in asset profiles. EnQuest has recognised UK corporate tax losses carried forward at 31 December 2022 amounting to $2,497.7 million (31 December 2021: $3,011.0 million), with unrecognised tax losses disclosed in note 7(d) on page 41.

Trade and other payables

Trade and other payables of $426.6 million at 31 December 2022 are $7.4 million higher than at 31 December 2021 ($420.5 million). The full balance of

$426.6 million is payable within one year.

Financial risk management

The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. The disclosures in relation to financial risk management objectives and policies, including the policy for hedging, and the disclosures in relation to exposure to oil price, foreign currency and credit and liquidity risk, are included in note 27 of the financial statements.

Going concern disclosure

The Group closely monitors and manages its funding position and liquidity risk throughout the year, including monitoring forecast covenant results, to ensure that it has access to sufficient funds to meet forecast cash requirements. Cash forecasts are regularly produced and sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and costs. These forecasts and sensitivity analyses allow management to mitigate liquidity or covenant compliance risks in a timely manner.

During 2022, the Group successfully completed a refinancing of its debt facilities, securing a $500.0 million amended and restated reserve based lending facility ('RBL') with a $300.0 million accordion maturing in April 2027 and $305.0 million 11.625% high yield bond maturing in November 2027. The net proceeds from the issue of the high yield bond, along with drawings of $400.0 million under the RBL and cash on hand, were used for the redemption of the $792.3 million aggregate principal amount of the Company's 7.00% high yield bond due 2023. This refinancing was in addition to the 9.00% retail bond exchange and issuance in April 2022 which resulted in a principal issue of £133.3 million. £111.3 million of the October 2023 7.00% retail bond remains in issue.

The RBL requires completion of a semi-annual review and redetermination on 30 June and 31 December each year. The amount available to draw under the RBL is based on an amortisation schedule and the borrowing base availability derived from the semi-annual review.

The RBL review and redetermination for the first half of 2023 was updated to include the increase in the EPL rate to 35%, extension of duration until March 2028 and removal of the windfall tax price floor introduced in the Autumn Statement 2022. This has resulted in a reduction of the available RBL capacity, and therefore liquidity available to the Group. In the first quarter of 2023, EnQuest repaid $118.0 million of the RBL facility, bringing the cash drawn balance down to $282 million, ensuring the Group remains ahead of the amended amortisation profile. The amended RBL repayment profile includes a further c.$100.0 million RBL deleveraging during the going concern period.

The Group's latest approved business plan, which includes the aforementioned RBL redetermination, underpins management's base case ('Base Case') and is in line with the Group's production guidance and uses oil price assumptions of $78.5/bbl for 2023 and 2024, adjusted for hedging activity undertaken.

The Base Case indicates that the Group is able to operate as a going concern and remain covenant compliant for 12 months from the date of publication of its full-year results. The Base Case reflects rapid deleveraging during the period, with redemption of the £111.3 million 7% retail bond in October 2023 and further RBL amortisations totalling c.$100.0 million, in addition to a $50.0 million contingent consideration payment in relation to the Golden Eagle acquisition in July 2023.

A reverse stress test has been performed on the Base Case. Given the rapid deleveraging required under the amended amortisation profile within the going concern period, an oil price of c.$77.0/bbl maintains covenant compliance. The Base Case has also been subjected to further testing through (i) a $5.00/bbl reduction in the average price from the Base Case; and (ii) a scenario reflecting the impact of the following plausible downside risks (the 'Downside Case'):

• 10.0% discount to Base Case prices resulting in Downside Case prices of $70.7/bbl for 2023 and 2024;

• Production risking of 5.0% for 2023 and 2024; and

• 2.5% increase in operating costs.

The case with $5.00/bbl reduction in the average price from the Base Case and the Downside Case indicate that mitigants would be required to remain covenant compliant. Should circumstances arise that differ from the Group's Base Case projections, the Directors believe that several mitigating actions, including working capital management, cargo prepayment or other funding options, can be executed successfully in the necessary timeframe to meet debt repayment obligations as they become due and maintain liquidity.

After making appropriate enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing these financial statements.

Viability statement

The Directors have assessed the viability of the Group over a three-year period to March 2026. The viability assumptions are consistent with the going concern assessment, with the additional inclusion of an oil price of $75.0/bbl for 2025 and a longer-term price of $70.0/bbl from 2026 in the Base Case and consistent plausible downside risks applied in a Downside Case. This assessment has taken into account the Group's financial position as at 4 April 2023, its future projections and the Group's principal risks and uncertainties. The Directors' approach to risk management, their assessment of the Group's principal risks and uncertainties, which includes potential impacts from climate change concerns and related regulatory developments, and the actions management are taking to mitigate these risks are outlined on pages 16 to 25. The period of three years is deemed appropriate as it is the time horizon across which management constructs a detailed plan against which business performance is measured. Based on the Group's projections the Directors have a reasonable expectation that the Group can continue in operation and meet its liabilities as they fall due over the period to April 2026.

The Base Case has further been stress tested to understand the impact on the Group's liquidity and financial position of reasonably possible changes in these risks and/or assumptions. For the current assessment, the Directors also draw attention to the specific principal risks and uncertainties (and mitigants) identified below, which, individually or collectively, could have a material impact on the Group's viability during the period of review. In forming this view, it is recognised that such future assessments are subject to a level of uncertainty that increases with time and, therefore, future outcomes cannot be guaranteed or predicted with certainty. The impact of these risks and uncertainties has been reviewed on both an individual and combined basis by the Directors, while considering the effectiveness and achievability of potential mitigating actions.

Oil price volatility

A decline in oil prices would adversely affect the Group's operations and financial condition. To mitigate oil price volatility, the Directors have hedged a total of 7.9 MMbbls for 2023, using costless collars and puts. The average floor price is c.$58.0/bbl and the average ceiling price associated with the 3.3 MMbbls of costless collars is c.$75.0/bbl. For 2024, the Group has hedged a total of 3.2 MMbbls through puts, with an average floor price of c.$60.0/bbl. The Directors, in line with Group policy and the terms of its RBL facility, will continue to pursue hedging at the appropriate time and price.

Fiscal risk and government take

Unanticipated changes in the regulatory or fiscal environment can affect the Group's ability to access funding and liquidity. The change to the UK EPL introduced in the Autumn Statement 2022 materially impacted the RBL borrowing base and associated amortisation schedule. The amended amortisation schedule is assumed in the Base Case.

Access to funding

Prolonged low oil prices, cost increases, production delays or outages and changes to the fiscal environment could threaten the Group's liquidity and access to funding.

The Directors recognise the importance of ensuring medium term liquidity. The maturity date of the $305.0 million high yield bond and the £133.3 million 9.00% retail bonds is November 2027, providing a material level of funding beyond the viability period. As stated above, the amendments to EPL impacted the RBL amortisation schedule, which is reflected in the Base Case. The Group will continue to prioritise debt reduction from free cash flows to ensure it remains ahead of this amended amortisation profile.

In assessing viability, the Directors recognise that in a Downside Case additional liquidity would be required, which may necessitate asset sales or other financing or funding options. Given the extended duration of the viability period, the Directors believe such measures can be executed successfully in the necessary timeframe to meet debt repayment obligations as they become due and maintain liquidity.

Notwithstanding the principal risks and uncertainties described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group can continue in operation and meet its commitments as they fall due over the viability period ending April 2026. Accordingly, the Directors therefore support this viability statement.

Risks and uncertainties

Management of risks and uncertainties

Consistent with the Group's purpose, the Board has articulated EnQuest's strategic vision to be the partner of choice for responsible management of

existing energy assets, applying our core capabilities to create value through the transition. EnQuest seeks to balance its risk position between investing in activities that can achieve its near-term targets, including those associated with reducing emissions, and those which can drive future growth with the

appropriate returns, including any appropriate market opportunities that may present themselves, and the continuing need to remain financially disciplined. This combination drives cost efficiency and cash flow generation, facilitating the continued reduction in the Group's debt.

In pursuit of its strategy, EnQuest has to manage a variety of risks. Accordingly, the Board has established a Risk Management Framework ('RMF') to

enhance effective risk management within the following Board-approved overarching statements of risk appetite:

The Group makes investments and manages the asset portfolio against agreed key performance indicators consistent with the strategic objectives of enhancing net cash flow, reducing leverage, reducing emissions, managing costs, diversifying its asset base and pursuing new energy and decarbonisation opportunities;

• The Group seeks to embed a culture of risk management within the organisation corresponding to the risk appetite which is articulated for each of its principal risks;

• The Group seeks to avoid reputational risk by ensuring that its operational and HSEA processes, policies and practices reduce the potential for error and harm to the greatest extent practicable by means of a variety of controls to prevent or mitigate occurrence; and

• The Group sets clear tolerances for all material operational risks to minimise overall operational losses, with zero tolerance for criminal conduct.

The Board reviews the Group's risk appetite annually in light of changing market conditions and the Group's performance and strategic focus. The Executive Committee periodically reviews and updates the Group Risk Register based on the individual risk registers of the business. The Group Risk Register; an assurance mapping and controls review exercise; a Risk Report (focused on identifying and mitigating the most critical and emerging risks through a systematic analysis of the Group's business, its industry and the global risk environment); and a Continuous Improvement Plan ('CIP') are periodically reviewed by the Board (with senior management) to ensure that key issues are being adequately identified and actively managed. In addition, the Group's Audit Committee oversees the effectiveness of the RMF while the Safety, Sustainability and Risk Committee provides a forum for the Board to review selected individual risk areas in greater depth.

As part of its strategic, business planning and risk processes, the Group considers how a number of macroeconomic themes may influence its principal risks. These are factors which the Group should be cognisant of when developing its strategy. They include, for example, long-term supply and demand trends for oil and gas and renewable energy, developments in technology, demographics, the financial, physical and transition risks associated with climate change and other ESG trends, and how markets and the regulatory environment may respond, and the decommissioning of infrastructure in the UK North Sea and other mature basins. These themes are relevant to the Group's assessments across a number of its principal risks. The Group

will continue to monitor these themes and the relevant developing policy environment at an international and national level, adapting its strategy accordingly. For example, the Group has made further progress in the development and execution of its energy transition and decarbonization strategy through the Infrastructure and New Energy business, which was established in 2021. The Group is also conscious that as an operator of mature producing assets with limited appetite for exploration, it has limited exposure to investments that do not deliver near-term returns and is therefore in a position to adapt and calibrate its exposure to new investments according to developments in relevant markets. This flexibility also ensures the Group

has mitigation against the potential impact of 'stranded assets'. Within the Group's RMF, the Safety, Sustainability and Risk Committee has categorised all risk areas faced by the Group into a 'Risk Library' of 19 overarching risks. For each risk area, 'Risk Bowties' are used to identify risk causes and impacts, with these mapped against preventative and containment controls used to manage the risks to acceptable level. These Risk Bowties are periodically reviewed to ensure they remain fit for purpose. The Board, supported by the Audit Committee and the Safety, Sustainability and Risk Committee, has reviewed the Group's system of risk management and internal control for the period from 1 January 2022 to the date of this report and carried out a robust assessment of the Group's emerging and principal risks and the procedures in place to identify and mitigate these risks. A Risk Management Framework

Performance report is produced and reviewed at each Safety, Sustainability and Risk Committee meeting in support of this review. The Board confirms that the Group complies with the Financial Reporting Council's 'Guidance on Risk Management, Internal Control and Related Financial and Business

Reporting'.

Near-term and emerging risks

As outlined previously, the Group's RMF is embedded in all levels of the organisation with asset risk registers, regional and functional risk registers and ultimately an enterprise-level 'Risk Library'. This integration enables the Group to identify quickly, escalate and appropriately manage emerging risks.

During 2022, work continued to enhance the integration of these risk registers and the associated processes to allow management to understand better the various asset risks and how these ultimately impact on the enterprise-level risk and their associated 'Risk Bowties'. A key area of ongoing development is the integration of the Operational Risk Assessment into the automated risk management software, which is expected to be completed in 2023. In turn, this ensures that the preventative and containment controls in place for a given risk are reviewed and remain robust based upon the identified risk profile. It also drives the required prioritisation of in-depth reviews to be undertaken by the Safety, Sustainability and Risk Committee, which are now integrated into the Group's internal audit programme for review. During the year, nine Risk Bowties were reviewed, ensuring that all 19 of the Group's identified risks have been reviewed within the targeted cycle.

With the threat from COVID-19 reduced and now being managed through updated and effective communicable disease procedures, the Group has removed it from its emerging risk register.

While not considered an emerging risk, given the focus on climate-related risks for energy companies, EnQuest has provided further detail below on its assessment of this risk within the Group's risk library.

Risk

Climate Change

The Group recognises that climate change concerns and related regulatory developments could impact a number of the Group's principal risks, such as oil price, financial, reputational and fiscal and government take risks, which are disclosed later in this report.

Appetite

EnQuest recognises that the oil and gas industry, alongside other key stakeholders such as governments, regulators and consumers, must all play a part in reducing the impact of carbon-related emissions on climate change, and is committed to contributing positively towards the drive to net zero through the energy transition and decarbonisation strategy being pursued through the Infrastructure and New Energy business.

The Group's risk appetite for climate change risk is reported against the Group's impacted principal risks, while a discrete disclosure against the Task Force on Climate-related Financial Disclosures can be found in the Annual Report.

Mitigation

Mitigations against the Group's principal risks potentially impacted by climate change are reported later in this report.

The Group has an emissions management strategy and has committed to a 10% reduction in Scope 1 and 2 emissions over three years, from a

year-end 2020 baseline, with the achievement linked to reward. Progress is reported to the Safety, Sustainability and Risk Committee of the Board. The Group endeavours to reduce emissions through improving operational performance, minimising flaring and venting where possible, and applying appropriate and economic improvement initiatives, noting that the ability to reduce carbon emissions from its own operations will be constrained by the original design of later-life assets. Following the establishment of the Infrastructure and New Energy business in 2021, the Group has further enhanced its business model to include a focus on repurposing existing infrastructure to support its renewable energy and decarbonisation ambitions, centred around the Sullom Voe Terminal.

EnQuest has reported on all of the greenhouse gas emission sources within its operational control required under the Companies Act 2006 (Strategic Report and Directors' Reports) Regulations 2013 and The Companies (Directors' Report) and Limited Liability Partnerships (Energy and Carbon Report) Regulations 2018.

The Group's focus on short-cycle investments drives an inherent mitigation against the potential impact of 'stranded assets'.

Risk

Ongoing geopolitical situation

The Group has continued to assess its commercial and IT security arrangements and does not consider it has a material adverse exposure to the geopolitical situation with respect to the sanctions imposed on Russia, although recognises that the situation has caused oil price volatility. The Group continues to monitor its position to ensure it remains compliant with any sanctions in place.

Risk

Fiscal risk and government take

The imposition of the UK Energy Profits Levy ('EPL') may materially affect EnQuest's free cash flow generation, which in turn will impact the Group's ability to finance growth opportunities, presenting a further challenge for future growth. The Group will continue to seek value-accretive opportunities, both through the pursuit of creative acquisition structures and continued focus on new energy projects.

Note that EPL could also impact the principal risks of Portfolio Concentration and Financial.

Key business risks

The Group's principal risks (identified from the 'Risk Library') are those which could prevent the business from executing its strategy and creating value for

shareholders or lead to a significant loss of reputation. The Board has carried out a robust assessment of the principal risks facing the Group at the February meeting, including those that would threaten its business model, future performance, solvency or liquidity.

Cognisant of the Group's purpose and strategy, the Board is satisfied that the Group's risk management system works effectively in assessing and managing the Group's risk appetite and has supported a robust assessment by the Directors of the principal risks facing the Group.

Set out on the following pages are:

• The principal risks and mitigations;

• An estimate of the potential impact and likelihood of occurrence after the mitigation actions, along with how these have changed in the past year; and

• An articulation of the Group's risk appetite for each of these principal risks.

Among these, the key risks the Group currently faces are materially lower oil prices for an extended period (see 'Oil and gas prices' risk on page 19), and/or a materially lower than expected production performance for a prolonged period (see 'Production' risk on pages 19 to 20 and 'Subsurface risk and reserves replacement' on page 22), and/or further changes in the fiscal environment (see 'Financial' risk on page 20 and 'Fiscal risk and government take' on pages 22 to 23), which could reduce the Group's cash generation and pace of deleveraging, which may in turn impact the Company's ability to comply with the requirements of its debt facilities and/or execute growth opportunities.

Risk

Health, safety and environment ('HSE')

Oil and gas development, production and exploration activities are by their very nature complex, with HSE risks covering many areas, including major accident hazards, personal health and safety, compliance with regulatory requirements, asset integrity issues and potential environmental impacts, including those associated with climate change.

Potential impact

Medium (2021 Medium)

Likelihood

Medium (2021 Medium)

There has been no material change in the potential impact or likelihood of this risk. The Group has a strong, open and transparent reporting culture and monitors both leading and lagging indicators and incurs substantial costs in complying with HSE requirements. The Group's overall record on HSE has been strong, albeit impacted by regulatory challenges in relation to the management of the annual flare consent on Magnus and the receipt

of improvement notices from the Health and Safety Executive.

Appetite

The Group's principal aim is SAFE Results with no harm to people and respect for the environment. Should operational results and safety ever come into conflict, employees have a responsibility to choose safety over operational results. Employees are empowered to stop operations for safety-related reasons.

The Group's desire is to maintain upper quartile HSE performance measured against suitable industry metrics.

In 2022, EnQuest achieved an upper quartile Lost Time Incident frequency rate1('LTIF'); however, the hydrocarbon release frequency rate was challenged due to three releases during the year. None of the releases had common root causes and occurred at three different locations and after thorough investigation no systemic failure was identified within our systems. The incidents occurred in the first half of the year and, since the corrective and preventative actions have been implemented, no further incidents occurred in the second half of 2022.

1 Lost Time Incident frequency represents the number of incidents per million exposure hours worked (based on 12 hours for offshore and eight hours for onshore)

Mitigation

The Group maintains, in conjunction with its core contractors, a comprehensive programme of assurance activities and has undertaken a series of

in-depth reviews into the Risk Bowties that have demonstrated the robustness of the management process and identified opportunities for improvement. A refreshed Group-aligned HSE Continuous Improvement Plan was created in 2022, promoting a culture of accountability and performance in relation to HSE matters. The purpose of this plan is to ensure that everyone understands what is expected of them by having realistic standards, governance and capabilities to add value and support the business. HSE performance is discussed at each Board meeting and the mitigation of HSE risk continues to be a core responsibility of the Safety, Sustainability and Risk Committee. During 2022, the Group continued to focus on the control of major accident hazards and SAFE Behaviours.

In addition, the Group has positive and transparent relationships with the UK Health and Safety Executive and Department for Business, Energy & Industrial Strategy, and the Malaysian regulator, PETRONAS Malaysia Petroleum Management.

EnQuest's HSE Policy is fully integrated across its operated sites and this has enabled an increased focus on HSE. There is a strong assurance programme in place to ensure EnQuest complies with its policy and principles and regulatory commitments.

Risk

Oil and gas prices

A material decline in oil and gas prices adversely affects the Group's operations and financial condition as the Group's revenue depends substantially on oil prices.

Potential impact

High (2021 High)

Likelihood

High (2021 High)

The potential impact and likelihood remain high, reflecting the uncertain economic outlook, including possible impacts from a global recession, geopolitical tensions and associated sanctions, and the potential acceleration of 'peak oil' demand.

The Group recognises that climate change concerns and related regulatory developments are likely to reduce demand for hydrocarbons over time. This may be mitigated by correlated constraints on the development of new supply. Further, oil and gas will remain an important part of the energy mix, especially in developing regions.

Appetite

The Group recognises that considerable exposure to this risk is inherent to its business but is committed to protecting cash flows in line with the terms of its reserve based lending facility.

Mitigation

This risk is being mitigated by a number of measures.

As an operator of mature producing assets with limited appetite for exploration, the Group has limited exposure to investments which do not deliver near-term returns and is therefore in a position to adapt and calibrate its exposure to new investments according to developments in relevant markets.

The Group monitors oil price sensitivity relative to its capital commitments and its assessment of the funds required to support investment in the development of its resources. The Group will therefore regularly review and implement suitable programmes to hedge against the possible negative impact of changes in oil prices within the terms of its established policy and the terms of the Group's reserve based lending facility, which requires hedging of EnQuest's entitlement sales volumes. As at 4 April 2023, the Group had hedged approximately 11.1 MMbbls for 2023 and 2024. This ensures that the Group will receive a minimum oil price for some of its production.

The Group has an established in-house trading and marketing function to enable it to enhance its ability to mitigate the exposure to volatility in oil prices. Further, the Group's focus on production efficiency supports mitigation of a low oil price environment.

Risk

Production

The Group's production is critical to its success and is subject to a variety of risks, including: subsurface uncertainties; operating in a mature field environment; potential for significant unexpected shutdowns; and unplanned expenditure (particularly where remediation may be dependent on suitable weather conditions offshore).

Lower than expected reservoir performance or insufficient addition of new resources may have a material impact on the Group's future growth.

Longer-term production is threatened if low oil prices or prolonged field shutdowns and/or underperformance requiring high-cost remediation bring forward decommissioning timelines.

Potential impact

High (2021 High)

Likelihood

Medium (2021 Medium)

There has been no material change in the potential impact or likelihood. The Group met its 2022 production guidance and continues to focus on key maintenance activities during planned shutdowns and procuring a stock of critical spares to support facility uptime.

Appetite

Since production efficiency and meeting production targets are core to EnQuest's business, the Group seeks to maintain a high degree of operational control over production assets in its portfolio. EnQuest has a very low tolerance for operational risks to its production (or the support systems that underpin production).

Mitigation

The Group's programme of asset integrity and assurance activities provide leading indicators of significant potential issues, which may result in unplanned shutdowns, or which may in other respects have the potential to undermine asset availability and uptime. The Group continually assesses the condition of its assets and operates extensive maintenance and inspection programmes designed to minimise the risk of unplanned shutdowns and expenditure.

The Group monitors both leading and lagging KPIs in relation to its maintenance activities and liaises closely with its downstream operators to minimise pipeline and terminal production impacts.

Production efficiency is continually monitored, with losses being identified and remedial and improvement opportunities undertaken as required. A continual, rigorous cost focus is also maintained.

Life of asset production profiles are audited by independent reserves auditors. The Group also undertakes regular internal reviews. The Group's forecasts of production are risked to reflect appropriate production uncertainties.

The Sullom Voe Terminal has a good safety record, and its safety and operational performance levels are regularly monitored and challenged by the Group and other terminal owners and users to ensure that operational integrity is maintained. Further, EnQuest is committed to transforming the Sullom Voe Terminal to ensure it remains competitive and well placed to maximise its useful economic life and support the future of the North Sea.

The Group actively continues to explore the potential of alternative transport options and developing hubs that may provide both risk mitigation and cost savings.

The Group also continues to consider new opportunities for expanding production.

Risk

Financial

Inability to fund financial commitments or maintain adequate cash flow and liquidity and/or reduce costs.

Significant reductions in the oil price, production and/or the funds available under the Group's reserve based lending ('RBL') facility, and/or further changes in the UK's fiscal environment, will likely have a material impact on the Group's ability to repay or refinance its existing credit facilities and invest in its asset base. Prolonged low oil prices, cost increases, including those related to an environmental incident, and production delays or outages, could threaten the Group's liquidity and/or ability to comply with relevant covenants. Further information is contained in the Financial review, particularly within the going concern and viability disclosures on pages 15 to 16.

Potential impact

High (2021 High)

Likelihood

High (2021 High)

There is no change to the potential impact or likelihood. While the Group has significantly reduced its debt and successfully refinanced its debt facilities in 2022, which extended maturities to 2027, the imposition of the Energy Profits Levy ('EPL') in the UK has impacted the level of available capital and associated amortisation schedule under the Group's RBL facility (see the going concern disclosures on pages 15 to 16).

Factors such as climate change, other environmental, social and governance ('ESG') concerns, oil price volatility and geopolitical risks have impacted investors' and insurers' acceptable levels of oil and gas sector exposure, with the availability of capital reducing while the cost of capital has increased. In addition, the cost of emissions trading allowances may continue to trend higher along with the potential for insurers to be reluctant to provide surety bonds for decommissioning, thereby requiring the Group to fund decommissioning security through its balance sheet.

Appetite

The Group remains focused on further reducing its leverage levels, targeting 0.5x EnQuest net debt to EBITDA ratio on a mid-cycle oil price basis, maintaining liquidity, controlling costs and complying with its obligations to finance providers while delivering shareholder value, recognising that reasonable assumptions relating to external risks need to be made in transacting with finance providers.

Mitigation

Debt reduction remains a strategic priority. During 2022, the Group's strong free cash flow generation drove a $504.9 million reduction in EnQuest net debt to $717.1 million at 31 December 2022, with an EnQuest net debt to adjusted EBITDA ratio of 0.7x. During the year, EnQuest also refinanced its debt facilities, rebalancing the capital structure and extending maturities to 2027. At 4 April 2023, the Group's new RBL facility was drawn to $282 million, with repayments totalling $118 million in the first quarter of 2023 ensuring the Group remains ahead of the amended facility amortisation schedule and within its borrowing base limits.

Ongoing compliance with the financial covenants under the Group's reserve based lending facility is actively monitored and reviewed. EnQuest generates operating cash inflow from the Group's producing assets and reviews its cash flow requirements on an ongoing basis to ensure it has adequate resources for its needs.

Where costs are incurred by external service providers, the Group actively challenges operating costs. The Group also maintains a framework of internal controls.

These steps, together with other mitigating actions available to management, are expected to provide the Group with sufficient liquidity to meet its obligations as they fall due.

Risk

Competition

The Group operates in a competitive environment across many areas, including the acquisition of oil and gas assets, the marketing of oil and gas, the procurement of oil and gas services and access to human resources.

Potential impact

High (2021 High)

Likelihood

High (2021 High)

The potential impact and likelihood remain unchanged, with the introduction of the UK EPL likely to impact industry participants' investment views of the UK North Sea, a number of competitors assessing the acquisition of available oil and gas assets and the rising potential for consolidation (for example, through reverse mergers). Operating in a competitive industry may result in higher than anticipated prices for the acquisition of assets and licences.

Appetite

The Group operates in a mature industry with well-established competitors and aims to be the leading operator in the sector.

Mitigation

The Group has strong technical, commercial and business development capabilities to ensure that it is well positioned to identify and execute potential acquisition opportunities, utilising innovative structures, which may include the Group's competitive advantage of $2.5 billion of UK tax losses, as may be appropriate. The Group maintains good relations with oil and gas service providers and constantly keeps the market under review. EnQuest has a dedicated marketing and trading group of experienced professionals responsible for maintaining relationships across relevant energy markets, thereby ensuring the Group achieves the highest possible value for its production.

Risk

IT security and resilience

The Group is exposed to risks arising from interruption to, or failure of, IT infrastructure. The risks of disruption to normal operations range from loss in functionality of generic systems (such as email and internet access) to the compromising of more sophisticated systems that support the Group's operational activities. These risks could result from malicious interventions such as cyber-attacks or phishing exercises.

Potential impact

Medium (2021 Medium)

Likelihood

Medium (2021 Medium)

There has been no change to the potential impact or likelihood, with the Group continuing to monitor and enhance its IT security, having regard for the ongoing geopolitical situation.

Appetite

The Group endeavours to provide a secure IT environment that is able to resist and withstand any attacks or unintentional disruption that may compromise sensitive data, impact operations, or destabilise its financial systems; it has a very low appetite for this risk.

Mitigation

The Group has established IT capabilities and endeavours to be in a position to defend its systems against disruption or attack.

A number of tools to strengthen employee awareness continue to be utilised, including videos, presentations, Yammer posts and poster campaigns.

During 2022, the Audit Committee agreed to update its terms of reference to highlight its responsibilities more explicitly with regard to the IT control environment, with the IT controls to be regularly reviewed during meetings. The Audit Committee also reviewed the Group's cyber-security measures and its IT resourcing model, noting the Group has a dedicated cyber-security manager. Work on assessing the cyber-security environment and implementing improvements as necessary will continue during 2023.

Risk

Portfolio concentration

The Group's assets are primarily concentrated in the UK North Sea around a limited number of infrastructure hubs and existing production (principally oil) is from mature fields. This amplifies exposure to key infrastructure (including ageing pipelines and terminals), political/fiscal changes and oil price movements.

Potential impact

High (2021 High)

Likelihood

High (2021 High)

There has been no material change in the potential impact or likelihood. The Group is currently focused on oil production and does not have significant exposure to gas or other sources of income. However, the Group continues to assess acquisition growth opportunities with a view to improving its asset diversity over time.

Appetite

Although the extent of portfolio concentration is moderated by production generated in Malaysia, the majority of the Group's assets remain relatively concentrated in the UK North Sea and therefore this risk remains intrinsic to the Group.

Mitigation

This risk is mitigated in part through acquisitions. For all acquisitions, the Group uses a number of business development resources, both in the UK and internationally, to liaise with vendors/governments and evaluate and transact acquisitions. This includes performing extensive due diligence (using

in-house and external personnel) and actively involving executive management in reviewing commercial, technical and other business risks together with mitigation measures.

The Group also constantly keeps its portfolio under rigorous review and, accordingly, actively considers the potential for making disposals and divesting, executing development projects, making international acquisitions, expanding hubs and potentially investing in gas assets, export capability or renewable energy and decarbonisation projects where such opportunities are consistent with the Group's focus

on enhancing net revenues, generating cash flow and strengthening the balance sheet.

The Group has made good progress with its decarbonisation strategy, identifying three key focus areas of carbon capture and storage, electrification and green hydrogen production through its Infrastructure and New Energy business, which could provide diversified revenue opportunities in the long term.

Risk

Subsurface risk and reserves replacement

Failure to develop its contingent and prospective resources or secure new licences and/or asset acquisitions and realise their expected value.

Potential impact

High (2021 High)

Likelihood

Medium (2021 Medium)

There has been no material change in the potential impact or likelihood.

Low oil prices, lack of available funds for investment (see 'Financial' risk) or prolonged field shutdowns requiring high-cost remediation which accelerate cessation of production can potentially affect development of contingent and prospective resources and/or reserves certifications.

Appetite

Reserves replacement is an element of the sustainability of the Group and its ability to grow. The Group has some tolerance for the assumption of risk in relation to the key activities required to deliver reserves growth, such as drilling and acquisitions.

Mitigation

The Group puts a strong emphasis on subsurface analysis and employs industry-leading professionals. The Group continues to recruit in a variety of technical positions which enables it to manage existing assets and evaluate the acquisition of new assets and licences.

All analysis is subject to internal and, where appropriate, external review and relevant stage gate processes. All reserves are currently externally reviewed by a Competent Person.

The Group has material reserves and resources at Magnus, Kraken, Golden Eagle and PM8/Seligi that it believes can primarily be accessed through low-cost workovers, subsea drilling and tie-backs to existing infrastructure. During 2022, EnQuest successfully completed a number of well programmes at its Magnus and PM8/Seligi assets. EnQuest continues to evaluate the substantial 2C resources at Bressay and Bentley to identify future drilling prospects and plans to drill an exploration well at PM409 during 2023.

The Group continues to consider potential opportunities to acquire new production resources that meet its investment criteria.

Risk

Project execution and delivery

The Group's success will be partially dependent upon the successful execution and delivery of potential future projects, including decommissioning and Infrastructure and New Energy opportunities in the UK, that are undertaken.

Potential impact

Medium (2021 Medium)

Likelihood

Low (2021 Low)

The potential impact and likelihood remain unchanged. As the Group focuses on reducing its debt, its current appetite is to pursue short-cycle development projects and to manage its decommissioning and Infrastructure and New Energy projects over an extended period of time.

Appetite

The efficient delivery of projects has been a key feature of the Group's long-term strategy. The Group's appetite is to identify and implement short-cycle development projects such as infill drilling and near-field tie-backs in its Upstream business, industrialise decommissioning projects to ensure cost efficiency and unlock new energy and decarbonisation opportunities through innovative commercial structures. While the Group necessarily assumes significant risk when it sanctions a new project (for example, by incurring costs against oil price assumptions), or a decommissioning programme, it requires that risks to efficient project delivery are minimised.

Mitigation

The Group has teams which are responsible for the planning and execution of new projects with a dedicated team for each project. The Group has detailed controls, systems and monitoring processes in place, notably the Capital Projects Delivery Process and the Decommissioning Projects Delivery Process, to ensure that deadlines are met, costs are controlled and that design concepts and Field Development/Decommissioning Plans are adhered to and implemented. These are modified when circumstances require and only through a controlled management of change process and with the necessary internal and external authorisation and communication. The Group's UK decommissioning programmes are managed by a dedicated directorate with an experienced team who are driven to deliver projects safely at the lowest possible cost and associated emissions.

In Infrastructure and New Energy, the Group is working with experienced third-party organisations and aims to utilise innovative commercial structures to develop new energy and decarbonisation opportunities.

The Group also engages third-party assurance experts to review, challenge and, where appropriate, make recommendations to improve the processes for project management, cost control and governance of major projects. EnQuest ensures that responsibility for delivering time-critical supplier obligations and lead times are fully understood, acknowledged and proactively managed by the most senior levels within supplier organisations.

Risk

Fiscal risk and government take

Unanticipated changes in the regulatory or fiscal environment can affect the Group's ability to deliver its strategy/business plan and potentially impact revenue and future developments.

Potential impact

High (2021 High)

Likelihood

High (2021 Medium)

There has been no material change in the potential impact; however, the likelihood has increased given the implementation of, and subsequent change to, the UK EPL which will negatively impact free cash flow generation and therefore the Group's ability to balance further deleveraging and investment in its asset base.

Appetite

The Group faces an uncertain macroeconomic and regulatory environment.

Due to the nature of such risks and their relative unpredictability, it must be tolerant of certain inherent exposure.

Mitigation

It is difficult for the Group to predict the timing or severity of such changes. However, through Offshore Energies UK and other industry associations, the Group engages with government and other appropriate organisations in order to keep abreast of expected and potential changes; the Group also takes an active role in making appropriate representations as it has done throughout the implementation period of the UK EPL.

All business development or investment activities recognise potential tax implications and the Group maintains relevant internal tax expertise. At an operational level, the Group has procedures to identify impending changes in relevant regulations to ensure legislative compliance.

Risk

International business

While the majority of the Group's activities and assets are in the UK, the international business is still material. The Group's international business is subject to the same risks as the UK business (for example, HSEA, production and project execution); however, there are additional risks that the Group faces, including security of staff and assets, political, foreign exchange and currency control, taxation, legal and regulatory, cultural and language barriers and corruption.

Potential impact

Medium (2021 Medium)

Likelihood

Medium (2021 Medium)

There has been no material change in the impact or likelihood.

Appetite

In light of its long-term growth strategy, the Group seeks to expand and diversify its production (geographically and in terms of quantum); as such, it is tolerant of assuming certain commercial risks which may accompany the opportunities it pursues.

However, such tolerance does not impair the Group's commitment to comply with legislative and regulatory requirements in the jurisdictions in which it operates. Opportunities should enhance net revenues and facilitate strengthening of the balance sheet.

Mitigation

Prior to entering a new country, EnQuest evaluates the host country to assess whether there is an adequate and established legal and political framework in place to protect and safeguard first its expatriate and local staff and, second, any investment within the country in question.

When evaluating international business risks, executive management reviews commercial, technical, ethical and other business risks, together with mitigation and how risks can be managed by the business on an ongoing basis.

EnQuest looks to employ suitably qualified host country staff and work with good-quality local advisers to ensure it complies with national legislation, business practices and cultural norms, while at all times ensuring that staff, contractors and advisers comply with EnQuest's business principles, including those on financial control, cost management, fraud and corruption.

Where appropriate, the risks may be mitigated by entering into a joint venture with partners with local knowledge and experience.

After country entry, EnQuest maintains a dialogue with local and regional government, particularly with those responsible for oil, energy and fiscal matters, and may obtain support from appropriate risk consultancies. When there is a significant change in the risk to people or assets within a country, the Group takes appropriate action to safeguard people and assets.

Risk

Joint venture partners

Failure by joint venture parties to fund their obligations. Dependence on other parties where the Group is non-operator.

Potential impact

Medium (2021 Medium)

Likelihood

Low (2021 Low)

There has been no material change in the potential impact or likelihood.

Appetite

The Group requires partners of high integrity. It recognises that it must accept a degree of exposure to the creditworthiness of partners and evaluates this aspect carefully as part of every investment decision.

Mitigation

The Group operates regular cash call and billing arrangements with its co-venturers to mitigate the Group's credit exposure at any one point in time and keeps in regular dialogue with each of these parties to ensure payment. Risk of default is mitigated by joint operating agreements allowing the Group to take over any defaulting party's share in an operated asset and rigorous and continual assessment of the financial situation of partners.

The Group generally prefers to be the operator. The Group maintains regular dialogue with its partners to ensure alignment of interests and to maximise the value of joint venture assets, taking account of the impact of any wider developments.

Risk

Reputation

The reputational and commercial exposures to a major offshore incident, including those related to an environmental incident, or non-compliance with applicable law and regulation and/or related climate change disclosures, are significant. Similarly, it is increasingly important that EnQuest clearly articulates its approach to and benchmarks its performance against relevant and material ESG factors.

Potential impact

High (2021 High)

Likelihood

Low (2021 Low)

There has been no material change in the potential impact or likelihood.

Appetite

The Group has no tolerance for conduct which may compromise its reputation for integrity and competence.

Mitigation

All activities are conducted in accordance with approved policies, standards and procedures. Interface agreements are agreed with all core contractors.

The Group requires adherence to its Code of Conduct and runs compliance programmes to provide assurance on conformity with relevant legal and ethical requirements.

The Group undertakes regular audit activities to provide assurance on compliance with established policies, standards and procedures.

All EnQuest personnel and contractors are required to pass an annual anti-bribery and corruption course, an anti-facilitation of tax evasion course and a data privacy course.

All personnel are authorised to shut down production for safety-related reasons.

The Group has a clear ESG strategy, with a focus on health and safety (including asset integrity), emission reductions, looking after its employees, positively impacting the communities in which the Group operates, upholding a robust RMF and acting with high standards of integrity.

The Group is successfully implementing this strategy.

Risk

Human resources

The Group's success continues to be dependent upon its ability to attract and retain key personnel and develop organisational capability to deliver strategic growth. Industrial action across the sector, or the availability of competent people, could also impact the operations of the Group.

Potential impact

Medium (2021 Medium)

Likelihood

Medium (2021 Medium)

There has been no material change to potential impact or likelihood.

Appetite

As a low-cost, lean organisation, the Group relies on motivated and high-quality employees to achieve its targets and manage its risks.

The Group recognises that the benefits of a lean, flexible and diverse organisation require creativity and agility to protect against the risk of skills shortages.

Mitigation

The Group has established an able and competent employee base to execute its principal activities. In addition, the Group seeks to maintain good relationships with its employees and contractor companies and regularly monitors the employment market to provide remuneration packages, bonus plans and long-term share-based incentive plans that incentivise performance and long-term commitment from employees to the Group.

The Group recognises that its people are critical to its success and so is continually evolving EnQuest's end-to-end people management processes, including recruitment and selection, career development and performance management. This ensures that EnQuest has the right person for the job and that appropriate training, support and development opportunities are provided, with feedback collated to drive continuous improvement while delivering SAFE Results. The culture of the Group is an area of ongoing focus and employee surveys and forums have been undertaken to understand employees' views on areas, including diversity and inclusion, in order to develop appropriate action plans. EnQuest also recognises that fewer young people may join the industry due to climate change-related factors, although the Group's decarbonisation ambitions provide some mitigation to this dynamic. EnQuest aims to attract the best talent, recognising the value and importance of diversity. To ensure improved diversity in the Group's leadership, various targets have been implemented during 2022. The Group recognises that there is a gender pay gap within the organisation but that there is no issue with equal pay for the same tasks.

EnQuest has reviewed the appropriate balance for its onshore teams between site, office and home working to promote strong productivity and Business performance facilitated by an engaged workforce, adopting a hybrid approach. The Group will continue to monitor such practices, adapting as necessary. The Group also maintains market-competitive contracts with key suppliers to support the execution of work where the necessary skills do not exist within the Group's employee base.

Executive and senior management retention, succession planning and development remain important priorities for the Board. It is a Board-level priority that executive and senior management possess the appropriate mix of skills and experience to realise the Group's strategy.

Following its introduction in 2019, the Group's Global Employee Forum ('the Forum') has continued to add to EnQuest's employee communication and engagement strategy, improving interaction between the workforce and the Board. During the year, the Board reviewed the purpose of the Forum and determined that its purpose had changed and its primary function was now for the raising of non-strategic issues. As such, the Board agreed that the Forum should continue under the direction of the Director of People, Culture and Diversity. The Board, through its designated Directors for employee engagement, now undertake a wider programme of formal and informal engagement with employees in line with the requirements of the UK Corporate Governance Code to understand the views of the workforce.

KEY PERFORMANCE INDICATORS

	2022	2021	2020
ESG metrics:
Group LTIF¹	0.57	0.21	0.22
Emissions (kilo-tonnes of CO₂ equivalent) ²	1,051.9	1,164.1	1,361.0
Business performance data:
Production (Boepd)	47,259	44,415	59,116
Unit opex (production and transportation costs) ($/Boe)³	22.7	20.5	15.2
Cash expenditures ($ million)	174.8	117.6	173.0
Capital²	115.8	51.8	131.4
Decommissioning	59.0	65.8	41.6
Reported data:
Cash generated from operations ($ million)	1,026.1	756.9	567.2
EnQuest net debt including PIK ($ million)²	717.1	1,222.0	1,279.7
Net 2P reserves (MMboe)⁴	190	205	200

¹ Lost time incident frequency represents the number of incidents per million exposure hours worked (based on 12 hours for offshore and eight hours for onshore )

² Prior periods have been restated to reflect alignment of reporting methodologies for independent verification of 2022 data in Malaysia. Previously, 2021 was reported as 1,145.3ktCO₂e and 2020 as 1,342.8ktCO₂e

³ See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 63

⁴ EnQuest now reports 2P reserves on a working interest basis to align with its peer group. Prior period comparatives have been restated, with 2021 previously reported at 194 MMboe and 2020 at 189 MMboe

OIL AND GAS RESERVES AND RESOURCES


ENQUEST OIL AND GAS RESERVES AND RESOURCES	UKCS		Other regions		Total
	MMboe	MMboe	MMboe	MMboe	MMboe
Proven and probable reserves 1, 2, 3, 4, 11
At 31 December 2021		174		20	194
Revisions of previous estimates	(3)		(4)
Transfers from contingent resources 5	4		5
		1		1	2
Production:
Export meter	(15)		(2)
Volume adjustments 6	0		-
		(15)		(2)	(17)
Total proven and probable reserves at 31 December 2021		160		19	179
Change in reporting basis to working interest 7		-		11	11
Total proven and probable reserves at 31 December 2022 8		160		30	190
Contingent resources 2, 9, 11
At 31 December 2021		316		86	402
Promoted to reserves 10		(4)		(5)	(9)
Total contingent resources at 31 December 2022		312		81	393
Notes:

1 Opening reserves are quoted on a net entitlement basis

2 Proven and probable ('2P') reserves and contingent resources ('2C') have been assessed by the Group's internal reservoir engineers, utilising geological, geophysical, engineering and financial data

3 The Group's 2P reserves have been audited by a recognised Competent Person in accordance with the definitions set out under the 2018 Petroleum Resources Management System and supporting guidelines issued by the Society of Petroleum Engineers. These are based on a different set of forward price assumptions to those the Group has used for impairment testing resulting in different economic reserves

4 All UKCS volumes are presented pre-Sullom Voe Terminal ('SVT') value adjustment. EnQuest reports export volumes and excludes the minor quality adjustment made when those UKCS volumes are blended at SVT with oil from other fields

5 Transfers from 2C resources at Magnus, Golden Eagle and PM8/Seligi

6 Correction of export to sales volumes of 0.2 MMboe

7 EnQuest has changed its reporting of Malaysian 2P reserves to a working interest basis to align with peer reporting (from an entitlement interest basis)

8 The above 2P reserves include volumes that will be consumed as fuel gas, including c.6.7 MMboe at Magnus, c.0.6 MMboe at Kraken and c.0.4 MMboe at Golden Eagle

9 Contingent resources are quoted on a working interest basis and relate to technically recoverable hydrocarbons for which commerciality has not yet been determined and are stated on a best technical case or 2C basis

10 Magnus, Golden Eagle and PM8/Seligi opportunity maturation 11 Rounding may apply

Group Income Statement

For the year ended 31 December 2022

		2022			2021
	Notes	Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in year $'000		Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in year $'000
Revenue and other operating income	5(a)	1,839,147	14,475	1,853,622		1,320,265	(54,451)	1,265,814
Cost of sales	5(b)	(1,195,806)	(4,900)	(1,200,706)		(900,433)	(7,201)	(907,634)
Gross profit/(loss)		643,341	9,575	652,916		419,832	(61,652)	358,180
Net impairment (charge)/reversal to oil and gas assets	4,10	-	(81,049)	(81,049)		-	39,715	39,715
General and administration expenses	5(c)	(7,553)	-	(7,553)		(363)	-	(363)
Other income	5(d)	76,247	7,706	83,953		30,990	162,647	193,637
Other expenses	5(e)	(2,810)	(233,570)	(236,380)		(7,278)	(3,832)	(11,110)
Profit/(loss) from operations before tax and finance income/(costs)		709,225	(297,338)	411,887		443,181	136,878	580,059
Finance costs	6	(176,227)	(36,410)	(212,637)		(169,451)	(58,395)	(227,846)
Finance income	6	1,816	2,148	3,964		228	-	228
Profit/(loss) before tax		534,814	(331,600)	203,214		273,958	78,483	352,441
Income tax	7	(322,468)	78,020	(244,448)		(53,674)	78,221	24,547
Profit/(loss) for the year attributable to owners of the parent		212,346	(253,580)	(41,234)		220,284	156,704	376,988
Total comprehensive (loss)/profit for the year, attributable to owners of the parent				(41,234)				376,988

There is no comprehensive income attributable to the shareholders of the Group other than the profit for the period. Revenue and operating profit/(loss) are all derived from continuing operations.

Earnings per share	8	$	$	$	$
Basic		0.114	(0.022)	0.127	0.217
Diluted		0.112	(0.022)	0.125	0.214

The attached notes 1 to 29 form part of these Group financial statements.

Group Balance Sheet

At 31 December 2022

	Notes	2022 $'000	2021 $'000
ASSETS
Non-current assets
Property, plant and equipment	10	2,476,975	2,821,998
Goodwill	11	134,400	134,400
Intangible assets	12	46,498	47,667
Deferred tax assets	7(c)	705,808	702,970
Other financial assets	19	6	6
		3,363,687	3,707,041
Current assets
Inventories	13	76,418	73,023
Trade and other receivables	16	276,363	296,068
Current tax receivable		1,491	2,368
Cash and cash equivalents	14	301,611	286,661
Other financial assets	19	4,705	472
		660,588	658,592
TOTAL ASSETS		4,024,275	4,365,633
EQUITY AND LIABILITIES
Equity
Share capital and premium	20	392,196	392,196
Share-based payment reserve		11,510	6,791
Retained earnings	20	80,535	121,769
TOTAL EQUITY		484,241	520,756
Non-current liabilities
Borrowings	18	281,422	191,109
Bonds	18	452,386	1,081,596
Leases liabilities	24	362,966	442,500
Contingent consideration	22	513,677	380,301
Provisions	23	667,335	754,266
Deferred tax liabilities	7(c)	166,334	3,418
		2,444,120	2,853,190
Current liabilities
Borrowings	18	131,936	210,505
Bonds	18	134,544	-
Leases liabilities	24	119,100	128,281
Contingent consideration	22	123,198	30,477
Provisions	23	70,335	140,676
Trade and other payables	17	426,647	420,544
Other financial liabilities	19	50,966	55,247
Current tax payable		39,188	5,957
		1,095,914	991,687
TOTAL LIABILITIES		3,540,034	3,844,877
TOTAL EQUITY AND LIABILITIES		4,024,275	4,365,633

The attached notes 1 to 29 form part of these Group financial statements.

The financial statements were approved by the Board of Directors and authorised for issue on 4 April 2023 and signed on its behalf by:

Salman Malik

Chief Financial Officer

Group Statement of Changes in Equity

For the year ended 31 December 2022

	Share capital and share premium $'000	Share-based payments reserve $'000	Retained earnings $'000	Total $'000
Balance at 1 January 2021	345,420	1,016	(255,219)	91,217
Profit/(loss) for the year	-	-	376,988	376,988
Total comprehensive profit for the year	-	-	376,988	376,988
Issue of share capital, net of expenses	46,200	-	-	46,200
Share-based payment	-	6,351	-	6,351
Shares purchased on behalf of Employee Benefit Trust	576	(576)	-	-
Balance at 31 December 2021	392,196	6,791	121,769	520,756
Profit/(loss) for the year	-	-	(41,234)	(41,234)
Total comprehensive profit for the year	-	-	(41,234)	(41,234)
Share-based payment	-	4,719	-	4,719
Balance at 31 December 2022	392,196	11,510	80,535	484,241

The attached notes 1 to 29 form part of these Group financial statements.

Group Statement of Cash Flows

For the year ended 31 December 2022

	Notes	2022 $'000	2021 $'000
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations	29	1,026,149	756,928
Cash received from insurance		15,015	674
Cash received/(paid) on purchase of financial instruments		(1,354)	(277)
Decommissioning spend		(58,964)	(65,791)
Income taxes paid		(49,293)	(17,396)
Net cash flows from/(used in) operating activities		931,553	674,138
INVESTING ACTIVITIES
Purchase of property, plant and equipment		(107,668)	(43,712)
Purchase of intangible oil and gas assets		(8,168)	(8,127)
Purchase of other intangible assets	12	(1,199)	(10,052)
Payment of Magnus contingent consideration - Profit share	22	(45,975)	(968)
Acquisitions		-	(258,627)
Interest received		1,763	256
Net cash flows (used in)/from investing activities		(161,247)	(321,230)
FINANCING ACTIVITIES
Net proceeds of share issue		-	47,782
Net proceeds of loans and borrowings		65,473	125,000
Net repayment of loans and borrowings		(545,278)	(184,276)
Repayment of Magnus contingent consideration - Vendor loan	22	-	(73,728)
Shares purchased by Employee Benefit Trust		-	(576)
Payment of obligations under financing leases	24	(147,971)	(136,651)
Interest paid		(103,387)	(63,025)
Net cash flows (used in)/from financing activities		(731,163)	(285,474)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS		39,143	67,434
Net foreign exchange on cash and cash equivalents		(24,193)	(3,603)
Cash and cash equivalents at 1 January		286,661	222,830
CASH AND CASH EQUIVALENTS AT 31 DECEMBER		301,611	286,661
Reconciliation of cash and cash equivalents
Total cash at bank and in hand	14	293,866	276,970
Restricted cash	14	7,745	9,691
Cash and cash equivalents per balance sheet		301,611	286,661

The attached notes 1 to 29 form part of these Group financial statements.

Notes to the Group Financial Statements

For the year ended 31 December 2022

1. Corporate information

EnQuest PLC ('EnQuest' or the 'Company') is a public company limited by shares incorporated in the United Kingdom under the Companies Act and is registered in England and Wales and listed on the London Stock Exchange and on the Stockholm NASDAQ OMX. The address of the Company's registered office is 2^nd Floor, Charles House, 5-11 Regent Street, London, SW1Y 4LR.

The principal activities of the Company and its subsidiaries (together the 'Group') are to responsibly optimise production, leverage existing infrastructure, deliver a strong decommissioning performance and explore new energy and decarbonisation opportunities.

The Group's financial statements for the year ended 31 December 2022 were authorised for issue in accordance with a resolution of the Board of Directors on 4 April 2023.

A listing of the Group's companies is contained in note 28 to these Group financial statements.

2. Basis of preparation

The consolidated financial statements have been prepared in accordance with UK-adopted International Accounting Standards ('IAS') in conformity with the requirements of the Companies Act 2006. The accounting policies which follow set out those policies which apply in preparing the financial statements for the year ended 31 December 2022.

The Group financial information has been prepared on an historical cost basis, except for the fair value remeasurement of certain financial instruments, including derivatives and contingent consideration, as set out in the accounting policies. The presentation currency of the Group financial information is US Dollars ('$') and all values in the Group financial information are rounded to the nearest thousand ($'000) except where otherwise stated.

The Group's results on a UK-adopted International Financial Reporting Standards ('IFRS') basis are shown on the Group Income Statement as 'Reported in the year', being the sum of its Business performance results and its Remeasurements and exceptional items as permitted by IAS 1 (Revised) Presentation of Financial Statements. Remeasurements and exceptional items are items that management considers not to be part of underlying business performance and are disclosed separately in order to enable shareholders to understand better and evaluate the Group's reported financial performance. For further information see note 4.

Going concern

The financial statements have been prepared on the going concern basis.

The RBL review and redetermination for the first half of 2023 was updated to include the increase in the EPL rate to 35%, extension of duration until March 2028 and removal of the windfall tax price floor introduced in the Autumn Statement 2022. This has resulted in a reduction of the available RBL capacity, and therefore liquidity available to the Group. In the first quarter of 2023, EnQuest repaid $118.0 million of the RBL facility, bringing the cash drawn balance down to $282.0 million, ensuring the Group remains ahead of the amended amortisation profile. The amended RBL repayment profile includes a further c.$100.0 million RBL deleveraging during the going concern period.

The Base Case indicates that the Group is able to operate as a going concern and remain covenant compliant for 12 months from the date of publication of its full-year results. The Base Case reflects rapid deleveraging during the period, with redemption of the £111.3 million 7% retail bond in October 2023 and further RBL amortisations totalling c.$100 million, in addition to a $50 million contingent consideration payment in relation to the Golden Eagle acquisition in July 2023.

· 10.0% discount to Base Case prices resulting in Downside Case prices of $70.7/bbl for 2023 and $70.7/bbl for 2024;

· Production risking of 5.0% for 2023 and 2024; and

· 2.5% increase in operating costs.

New standards and interpretations

The following new standards became applicable for the current reporting period. No material impact was recognised upon application:

· Reference to the Conceptual Framework (Amendments to IFRS 3)

· Property, Plant and Equipment - Proceeds before intended use (Amendment to IAS 16)

· Onerous contracts - Cost of Fulfilling a Contract (Amendments to IAS 37)

· Annual improvements to IFRS Accounting Standards 2018-2020 Cycle

Standards issued but not yet effective

At the date of authorisation of these financial statements, the Group has not applied the following new and revised IFRS Standards that have been issued but are not yet effective:

IFRS 17	Insurance Contracts
IFRS 10 and IAS 28 (amendments)	Sale or Contribution of Assets between an Investor and its Associate or Joint Venture
Amendments to IAS 1 Amendments to IAS 8	Classification of Liabilities as Current or Non-current and Disclosure of Accounting Policies Disclosure of Accounting Policies
Amendments to IAS 12	Deferred Tax related to Assets and Liabilities arising from a Single Transaction

The Directors do not expect that the adoption of the Standards listed above will have a material impact on the financial statements of the Group in future periods.

Basis of consolidation

The consolidated financial statements incorporate the financial statements of EnQuest PLC and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved when the Company:

· has power over the investee;

· is exposed, or has rights, to variable returns from its involvement with the investee; and

· has the ability to use its power to affect its returns.

The Company reassesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control listed above. Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary. Specifically, the results of subsidiaries acquired or disposed of during the year are included in profit or loss from the date when the Company gains control until the date when the Company ceases to control the subsidiary.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used into line with the Group's accounting policies. All intra-Group assets and liabilities, equity, income, expenses and cash flows relating to transactions between the members of the Group are eliminated on consolidation.

Joint arrangements

Oil and gas operations are usually conducted by the Group as co-licensees in unincorporated joint operations with other companies. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the consent of the relevant parties sharing control. The joint operating agreement is the underlying contractual framework to the joint arrangement, which is historically referred to as the joint venture. The Annual Report and Accounts therefore refers to 'joint ventures' as a standard term used in the oil and gas industry, which is used interchangeably with joint operations.

Most of the Group's activities are conducted through joint operations, whereby the parties that have joint control of the arrangement have the rights to the assets, and obligations for the liabilities relating to the arrangement. The Group recognises its share of assets, liabilities, income and expenses of the joint operation in the consolidated financial statements on a line-by-line basis. During 2022, the Group did not have any material interests in joint ventures or in associates as defined in IAS 28.

Foreign currencies

Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates ('functional currency'). The Group's financial statements are presented in US Dollars, the currency which the Group has elected to use as its presentation currency.

In the financial statements of the Company and its individual subsidiaries, transactions in currencies other than a company's functional currency are recorded at the prevailing rate of exchange on the date of the transaction. At the year end, monetary assets and liabilities denominated in foreign currencies are retranslated at the rates of exchange prevailing at the balance sheet date. Non-monetary assets and liabilities that are measured at historical cost in a foreign currency are translated using the rate of exchange at the dates of the initial transactions. Non-monetary assets and liabilities measured at fair value in a foreign currency are translated using the rate of exchange at the date the fair value was determined. All foreign exchange gains and losses are taken to profit and loss in the Group income statement.

Emissions liabilities

The Group operates in an energy intensive industry and is therefore required to partake in emission trading schemes ('ETS'). The Group recognises an emission liability in line with the production of emissions that give rise to the obligation. To the extent the liability is covered by allowances held, the liability is recognised at the cost of these allowances held and if insufficient allowances are held, the remaining uncovered portion is measured at the spot market price of allowances at the balance sheet date. The expense is presented within 'production costs' under 'cost of sales' and the accrual is presented in 'trade and other payables'. Any allowance purchased to settle the Group's liability is recognised on the balance sheet as an intangible asset. Both the emission allowances and the emission liability are derecognised upon settling the liability with the respective regulator.

Use of judgements, estimates and assumptions

The preparation of the Group's consolidated financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities, and the accompanying disclosures, at the date of the consolidated financial statements. Estimates and assumptions are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to the carrying amount of assets or liabilities affected in future periods.

The accounting judgements and estimates that have a significant impact on the results of the Group are set out below and should be read in conjunction with the information provided in the Notes to the financial statements. The Group does not consider contingent consideration and deferred taxation (including EPL) to represent a significant estimate or judgement as the estimates and assumptions relating to projected earnings and cash flows used to assess contingent consideration and deferred taxation are the same as those applied in the Group impairment process as described below in Recoverability of asset carrying values . Judgements and estimates, not all of which are significant, made in assessing the impact of climate change and the transition to a lower carbon economy on the consolidated financial statements are also set out below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year, this is specifically noted.

Climate change and energy transition

As covered in our principal risks on oil and gas prices on page 19, the Group recognises that the energy transition is likely to impact the demand, and hence the future prices, of commodities such as oil and natural gas. This in turn may affect the recoverable amount of property, plant and equipment, and goodwill in the oil and gas industry. The Group acknowledges that there are a range of possible energy transition scenarios that may indicate different outcomes for oil prices. There are inherent limitations with scenario analysis and it is difficult to predict which, if any, of the scenarios might eventuate.

The Group has assessed the potential impacts of climate change and the transition to a lower carbon economy in preparing the consolidated financial statements, including the Group's current assumptions relating to demand for oil and natural gas and their impact on the Group's long-term price assumptions. See Recoverability of asset carrying values: Oil prices .

While the pace of transition to a lower carbon economy is uncertain, oil and natural 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 useful lives of the Group's current portfolio of oil and gas assets, a material adverse change is not expected to the carrying values of EnQuest's assets and liabilities as a result of climate change and the transition to a lower carbon economy.

Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals in the future.

Critical accounting judgements and key sources of estimation uncertainty

The Group has considered its critical accounting judgements and key sources of estimation uncertainty, and these are set out below.

Recoverability of asset carrying values

Judgements: The Group assesses each asset or cash-generating unit ('CGU') (excluding goodwill, which is assessed annually regardless of indicators) in each reporting period to determine whether any indication of impairment exists. Assessment of indicators of impairment or impairment reversal and the determination of the appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment purposes require significant management judgement. For example, individual oil and gas properties may form separate CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. See note 11 for details on how these groupings have been determined in relation to the impairment testing of goodwill.

Estimates: Where an indicator of impairment exists, a formal estimate of the recoverable amount is made, which is considered to be the higher of the fair value less costs to dispose ('FVLCD') and value in use ('VIU'). The assessments require the use of estimates and assumptions such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil and natural gas.

As described above, the recoverable amount of an asset is the higher of its VIU and its FVLCD. When the recoverable amount is measured by reference to FVLCD, in the absence of quoted market prices or binding sale agreement, estimates are made regarding the present value of future post-tax cash flows. These estimates are made from the perspective of a market participant and include prices, future production volumes, operating costs, capital expenditure, decommissioning costs, tax attributes, risking factors applied to cash flows and discount rates. Reserves and resources are included in the assessment of FVLCD to the extent that it is considered probable that a market participant would attribute value to them.

Details of impairment charges and reversals recognised in the income statement and details on the carrying amounts of assets are shown in note 10, note 11 and note 12.

The estimates for assumptions made in impairment tests in 2022 relating to discount rates and oil prices are discussed below. Changes in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the Group's assets within the next financial year.

Discount rates

For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. FVLCD discounted cash flow calculations use the post-tax discount rate. The discount rate is derived using the weighted average cost of capital methodology. The discount rates applied in impairment tests are reassessed each year and, in 2022, the post-tax discount rate increased to 11% (2021: 10%) reflecting market volatility and the increase in interest rates.

Oil prices

The price assumptions used for FVLCD impairment testing were based on latest internal forecasts as at 31 December 2022, which assume short-term market prices will revert to the Group's assessment of long-term price. These price forecasts reflect EnQuest's long-term views of global supply and demand, including the potential financial impacts on the Group of climate change and the transition to a low carbon economy as outlined in the Basis of Preparation, and are benchmarked with external sources of information such as analyst forecasts. The Group's price forecasts are reviewed and approved by management and challenged by the Audit Committee.

EnQuest revised its oil price assumptions for FVLCD impairment testing compared to those used in 2021. The assumptions were increased to reflect an improved demand outlook as at the end of 2022. Oil prices were higher than 2021 throughout much of 2022. They peaked at c.$130/bbl following the Russian invasion of Ukraine in March and remained elevated for the summer, driven by a combination of uncertainty over the impact of sanctions on Russia, measured increases in OPEC+ supply and continued capital discipline across the industry. Towards the end of 2022, prices declined towards c.$80/bbl as oil demand slowed, reflecting the combination of uncertainty over the pace at which COVID-19 related restrictions would be removed in China and mounting global inflation and recessionary pressures. A summary of the Group's revised price assumptions is provided below. These assumptions, which represent management's best estimate of future prices, sit within the range of external forecasts. They do not correspond to any specific Paris-consistent scenario, but when compared to the International Energy Agency's ('IEA') forecast prices under its Announced Pledges Scenario ('APS'), which is considered to be a scenario achieving an emissions trajectory consistent with keeping the temperature rise in 2100 below 2 degrees Celsius, could, on average, be considered to be broadly in line with a Paris-consistent scenario. EnQuest's short and medium term assumptions are below those assumed under the APS, while its longer term prices are slightly higher. The impact on the Group from the forecast prices under the APS are discussed in EnQuest's Task Force for Climate-related Financial Disclosures report in the annual report.

An inflation rate of 2% (2020: 2%) is applied from 2026 onwards to determine the price assumptions in nominal terms. Discounts or premiums are applied to price assumptions based on the characteristics of the oil produced and of the terms of the relevant sales contracts. The price assumptions used in 2021 were $75.0/bbl (2022), $70.0/bbl (2023), $70.0/bbl (2024) and $60.0/bbl real thereafter, inflated at 2.0% per annum from 2025.

	2023	2024	2025	2026>
Brent oil ($/bbl)	84.0	80.0	75.0	70.0

Oil and natural gas reserves

Hydrocarbon reserves are estimates of the amount of hydrocarbons that can be economically and legally extracted from the Group's oil and gas properties. The business of the Group is to responsibly optimise production, leverage existing infrastructure, deliver a strong decommissioning performance and explore new energy and decarbonisation opportunities. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the Group's estimates of its oil and gas reserves and result in different future production profiles affecting prospectively the discounted cash flows used in impairment testing and the calculation of contingent consideration, the anticipated date of decommissioning and the depletion charges in accordance with the unit of production method, as well as the going concern assessment. Economic assumptions used to estimate reserves change from period to period as additional technical and operational data is generated. This process may require complex and difficult geological judgements to interpret the data.

The Group uses proven and probable ('2P') reserves (see page 26) as the basis for calculations of expected future cash flows from underlying assets because this represents the reserves management intends to develop and it is probable that a market participant would attribute value to them. Third-party audits of EnQuest's reserves and resources are conducted annually.

Sensitivity analyses

Management tested the impact of a change in cash flows in FVLCD impairment testing arising from a 10% reduction in price assumptions.

Price reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of EnQuest's oil and gas properties by approximately $269.0 million, which is approximately 11% of the net book value of property, plant and equipment as at 31 December 2022.

The oil price sensitivity analysis above does not, however, represent management's best estimate of any impairments that might be recognised as it does not fully incorporate consequential changes that may arise, such as reductions in costs and changes to business plans, phasing of development, levels of reserves and resources, and production volumes. As the extent of a price reduction increases, the more likely it is that costs would decrease across the industry. The oil price sensitivity analysis therefore does not reflect a linear relationship between price and value that can be extrapolated.

Management also tested the impact of a one percentage point change in the discount rate used for FVLCD impairment testing of oil and gas properties which is considered a reasonably possible change given the prevailing macroeconomic environment. If the discount rate was one percentage point higher across all tests performed, the net impairment charge recognised in 2022 would have been approximately $62.7 million higher. If the discount rate was one percentage point lower, the net impairment charge recognised would have been approximately $68.1 million lower.

Goodwill

Irrespective of whether there is any indication of impairment, EnQuest is required to test annually for impairment of goodwill acquired in business combinations. The Group carries goodwill of approximately $134.4 million on its balance sheet (2021: $134.4 million), principally relating to the Magnus oil field transactions. Sensitivities and additional information relating to impairment testing of goodwill are provided in note 11.

Deferred tax

The Group assesses the recoverability of its deferred tax assets at each period end. Sensitivities and additional information relating to deferred tax assets/liabilities are provided in note 7(d).

75% Magnus acquisition contingent consideration

Estimates: Following the volatility in financial markets experienced in the second half of 2022, the Group reassessed the fair value discount rate associated with the Magnus contingent consideration. This was estimated to be 10.0% as at the end of 2022, as calculated in line with IFRS 13. Sensitivities and additional information relating to the 75% Magnus acquisition contingent consideration are provided in note 22.

Provisions

Estimates : Decommissioning costs will be incurred by the Group at the end of the operating life of some of the Group's oil and gas production facilities and pipelines. The Group assesses its decommissioning provision at each reporting date. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, estimates of the extent and costs of decommissioning activities, the emergence of new restoration techniques and experience at other production sites. The expected timing, extent and amount of expenditure may also change; for example, in response to changes in oil and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results, although this is not expected within the next year.

The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed half-yearly. The nominal interest rate used to determine the balance sheet obligations at the end of 2022 was increased to 3.5% (2021: 2%), reflecting increasing interest rates as the Bank of England sought to control inflation. The weighted average period over which decommissioning costs are generally expected to be incurred is estimated to be approximately ten years. Costs at future prices are determined by applying inflation rates for 2022 at 4% (2023), 3% (2024) and a long-term inflation rate of 2% thereafter (2021: 2% from 2022 onwards) to decommissioning costs.

Further information about the Group's provisions is provided in note 23. Changes in assumptions, including cost reduction factors, in relation to the Group's provisions could result in a material change in their carrying amounts within the next financial year. A 1.0 percentage point decrease in the nominal discount rate applied, which is considered a reasonably possible change given the prevailing macroeconomic environment, could increase the Group's provision balances by approximately $54.0 million (2021: $40.9 million). The pre-tax impact on the Group income statement would be a charge of approximately $53.6 million.

Intangible oil and gas assets

Judgements : The application of the Group's accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely from either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves.

3. Segment information

The Group's organisational structure reflects the various activities in which EnQuest is engaged. Management has considered the requirements of IFRS 8 Operating Segments in regard to the determination of operating segments and concluded that at 31 December 2022, the Group had two significant operating segments: the North Sea and Malaysia. Operations are managed by location and all information is presented per geographical segment. The Group's segmental reporting structure remained in place throughout 2022. The North Sea's activities include Upstream operations, Decommissioning and Infrastructure & New Energy. Malaysia's activities include Upstream operations. The Group's reportable segments may change in the future depending on the way that resources may be allocated and performance assessed by the Chief Operating Decision Maker, who for EnQuest is the Chief Executive. The information reported to the Chief Operating Decision Maker does not include an analysis of assets and liabilities, and accordingly this information is not presented, in line with IFRS 8 para 23.

Year ended 31 December 2022 $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations (i)	Consolidated
Revenue:
Revenue from contracts with customers	1,873,214	159,578	-	2,032,792	-	2,032,792
Other operating income/(expense)	9,832	-	264	10,096	(189,266)	(179,170)
Total revenue and other operating income/(expense)	1,883,046	159,578	264	2,042,888	(189,266)	1,853,622
Income/(expenses) line items:
Depreciation and depletion	(319,025)	(14,116)	(107)	(333,248)	-	(333,248)
Net impairment (charge)/reversal to oil and gas assets	(81,049)	-	-	(81,049)	-	(81,049)
Segment profit/(loss) (ii)	546,199	65,160	112	611,471	(199,584)	411,887
Other disclosures:
Capital expenditure(iii)	115,853	39,030	30	154,913	-	154,913

Year ended 31 December 2021 $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(i)	Consolidated
Revenue:
Revenue from contracts with customers	1,283,939	99,959	-	1,383,898	-	1,383,898
Other operating income/(expense)	3,811	-	235	4,046	(122,130)	(118,084)
Total revenue and other operating income/(expense)	1,287,750	99,959	235	1,387,944	(122,130)	1,265,814
Income/(expenses) line items:
Depreciation and depletion	(299,324)	(13,612)	(134)	(313,070)	-	(313,070)
Net impairment (charge)/reversal to oil and gas assets	39,715	-	-	39,715	-	39,715
Segment profit/(loss) (ii)	653,301	35,625	(291)	688,635	(108,576)	580,059
Other disclosures:
Capital expenditure(iii)	459,302	17,419	314	477,035	-	477,035

(i) Finance income and costs and gains and losses on derivatives are not allocated to individual segments as the underlying instruments are managed on a Group basis

(ii) Inter-segment revenues are eliminated on consolidation. All other adjustments are part of the reconciliations presented further below

(iii) Capital expenditure consists of property, plant and equipment and intangible exploration and appraisal assets, with 2021 reflecting the acquisition of the Golden Eagle asset

Reconciliation of profit/(loss):

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Segment profit/(loss)	611,471	688,635
Finance costs	(212,637)	(227,846)
Finance income	3,964	228
Gain/(loss) on oil and foreign exchange derivatives⁽ⁱ⁾	(199,584)	(108,576)
Profit/(loss) before tax	203,214	352,441

(i) Includes $209.2 million realised losses on derivatives and $9.6 million unrealised gains on derivatives

Revenue from two customers relating to the North Sea operating segment each exceeds 10% of the Group's consolidated revenue arising from sales of crude oil, with amounts of $365.1 million and $321.7 million per each single customer (2021: two customers; $241.7 million and $150.6 million per each single customer).

4. Remeasurements and exceptional items

Accounting policy

As permitted by IAS 1 (Revised) Presentation of Financial Statements, certain items of income or expense which are material are presented separately. Additional line items, headings, sub-totals and disclosures of the nature and amount are presented to provide relevant understanding of the Group's financial performance.

Remeasurements and exceptional items are items that management considers not to be part of underlying business performance and are disclosed in order to enable shareholders to understand better and evaluate the Group's reported financial performance. The items that the Group separately presents as exceptional on the face of the Group income statement are those material items of income and expense which, because of the nature or expected infrequency of the events giving rise to them, merit separate presentation to allow shareholders to understand better the elements of financial performance in the year, so as to facilitate comparison with prior periods and to better assess trends in financial performance. Remeasurements relate to those items which are remeasured on a periodic basis and are applied consistently year-on-year. If an item is assessed as a remeasurement or exceptional item, then subsequent accounting to completion of the item is also taken through remeasurement and exceptional items. Management has exercised judgement in assessing the relevant material items disclosed as exceptional.

The following items are classified as remeasurements and exceptional items ('exceptional'):

· Unrealised mark-to-market changes in the remeasurement of open derivative contracts at each period end are recognised within remeasurements, with the recycling of realised amounts from remeasurements into Business performance income when a derivative instrument matures;

· Impairments on assets, including other non-routine write-offs/write-downs where deemed material, are remeasurements and are deemed to be exceptional in nature;

· Fair value accounting arising in relation to business combinations is deemed as exceptional in nature, as these transactions do not relate to the principal activities and day-to-day Business performance of the Group. The subsequent remeasurements of contingent assets and liabilities arising on acquisitions, including contingent consideration, are presented within remeasurements and are presented consistently year-on-year; and

· Other items that arise from time to time that are reviewed by management as non-Business performance and are disclosed further below.

Year ended 31 December 2022 $'000	Fair value remeasurement (i)	Impairments and write-offs (ii)	Other (iii)	Total
Revenue and other operating income	14,475	-	-	14,475
Cost of sales	(4,900)	-	-	(4,900)
Net impairment (charge)/reversal on oil and gas assets	-	(81,049)	-	(81,049)
Other income	1,070	-	6,636	7,706
Other expense	(233,570)	-	-	(233,570)
Finance costs	-	-	(36,410)	(36,410)
Finance income	-	-	2,148	2,148
	(222,925)	(81,049)	(27,626)	(331,600)
Tax on items above	89,599	32,420	7,817	129,836
Recognition of undiscounted deferred tax asset^(iv)	-	127,024	-	127,024
Deferred UK Energy Profits Levy	-	-	(178,840)	(178,840)
	(133,326)	78,395	(198,649)	(253,580)

Year ended 31 December 2021 $'000	Fair value remeasurement(i)	Impairments and write-offs(ii)	Other(iii)	Total
Revenue and other operating income	(54,451)	-	-	(54,451)
Cost of sales	472	-	(7,673)	(7,201)
Net impairment (charge)/reversal on oil and gas assets	-	39,715	-	39,715
Other income	140,079	-	22,568	162,647
Other expenses	-	-	(3,832)	(3,832)
Finance costs	-	-	(58,395)	(58,395)
	86,100	39,715	(47,332)	78,483
Tax on items above	(36,518)	(14,722)	24,915	(26,325)
Recognition of undiscounted deferred tax asset^(iv)	-	104,546	-	104,546
	49,582	129,539	(22,417)	156,704

(i) Fair value remeasurements include unrealised mark-to-market movements on derivative contracts and other financial instruments and the impact of recycled realised gains and losses out of 'Remeasurements and exceptional items' and into Business performance profit or loss of $9.6 million (2021: $(54.0) million). Other expense net of other income relates to the fair value remeasurement of contingent consideration relating to the acquisition of Magnus and associated infrastructure of $232.5 million (note 22) (2021: other income of $140.1 million)

(ii) Impairments and write offs include a net impairment charge of tangible oil and gas assets and right-of-use assets totalling $81.0 million (note 10) (2021: reversal of $39.7 million)

(iii) Other items are made up of the following: In 2021, cost of sales included $7.7 million mainly related to a provision for a dispute with a third party contractor. Other income of $6.6 million in 2022 relates to recognition of insurance income related to PM8/Seligi riser incident. 2021 included the write-off of the fair value ascribed to accruals of $12.0 million as part of the accounting at the time of acquisition of the additional 75% in Magnus and the recognition of $9.0 million of insurance income related to the PM8/Seligi riser incident. In 2021, other expense of $3.8 million relates to expenses incurred on the repayment of the bp vendor loan. Finance costs relates to the finance cost element of the 75% acquisition of Magnus and associated infrastructure of $36.4 million (note 22) (2021: $58.3 million). Finance income of $2.1 million in 2022 represents a realised gain on the partial buy back of the Group's 7.00% high yield bond

(iv) Non-cash deferred tax recognition in 2022 due to the Group's higher oil price assumptions. In 2021 includes impact of Group's acquisition of Golden Eagle in addition to higher oil price assumptions

5. Revenue and expenses

(a) Revenue and other operating income

Accounting policy

Revenue from contracts with customers

The Group generates revenue through the sale of crude oil, gas and condensate to third parties, and through the provision of infrastructure to its customers for tariff income. Revenue from contracts with customers is recognised when control of the goods or services is transferred to the customer at an amount that reflects the consideration to which the Group expects to be entitled to in exchange for those goods or services. The Group has concluded that it is the principal in its revenue arrangements because it typically controls the goods or services before transferring them to the customer. The normal credit term is 30 days or less upon performance of the obligation.

Sale of crude oil, gas and condensate

The Group sells crude oil, gas and condensate directly to customers. The sale represents a single performance obligation, being the sale of barrels equivalent to the customer on taking physical possession or on delivery of the commodity into an infrastructure. At this point the title passes to the customer and revenue is recognised. The Group principally satisfies its performance obligations at a point in time; the amounts of revenue recognised relating to performance obligations satisfied over time are not significant. Transaction prices are referenced to quoted prices, plus or minus an agreed fixed discount rate to an appropriate benchmark, if applicable.

Tariff revenue for the use of Group infrastructure

Tariffs are charged to customers for the use of infrastructure owned by the Group. The revenue represents the performance of an obligation for the use of Group assets over the life of the contract. The use of the assets is not separable as they are interdependent in order to fulfil the contract and no one item of infrastructure can be individually isolated. Revenue is recognised as the performance obligations are satisfied over the period of the contract, generally a period of 12 months or less, on a monthly basis based on throughput at the agreed contracted rates.

Other operating income

Other revenue includes rental income from vessels, which is recognised to the extent that it is probable economic benefits will flow to the Group and the revenue can be reliably measured.

The Group enters into oil derivative trading transactions which can be settled net in cash. Accordingly, any gains or losses are not considered to constitute revenue from contracts with customers in accordance with the requirements of IFRS 15 rather are accounted for in line with IFRS 9 and included within other operating income (see note 19).

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Revenue from contracts with customers:
Revenue from crude oil sales	1,517,666	1,139,171
Revenue from gas and condensate sales(i)	514,206	244,073
Tariff revenue	920	654
Total revenue from contracts with customers	2,032,792	1,383,898
Rental income from vessels	-	702
Realised losses on oil derivative contracts (see note 19)	(203,741)	(67,679)
Other	10,096	3,344
Business performance revenue and other operating income	1,839,147	1,320,265
Unrealised gains/(losses) on oil derivative contracts(ii) (see note 19)	14,475	(54,451)
Total revenue and other operating income	1,853,622	1,265,814

(i) Includes onward sale of third-party gas purchases not required for injection activities at Magnus. (see note 5(b))

(ii) Unrealised gains and losses on oil derivative contracts are disclosed as fair value remeasurement items in the income statement (see note 4)

Disaggregation of revenue from contracts with customers

	Year ended 31 December 2022 $'000		Year ended 31 December 2021 $'000
	North Sea	Malaysia	North Sea	Malaysia
Revenue from contracts with customers:
Revenue from crude oil sales	1,360,228	157,438	1,040,577	98,594
Revenue from gas and condensate sales⁽ⁱ⁾	512,066	2,140	242,708	1,365
Tariff revenue	920	-	654	-
Total revenue from contracts with customers	1,873,214	159,578	1,283,939	99,959

(i) Includes onward sale of third-party gas purchases not required for injection activities at Magnus. (see note 5(b))

(b) Cost of sales

Accounting policy

Production imbalances, movements in under/over-lift and movements in inventory are included in cost of sales. The over-lift liability is recorded at the cost of the production imbalance to represent a provision for production costs attributable to the volumes sold in excess of entitlement. The under-lift asset is recorded at the lower of cost and net realisable value, consistent with IAS 2, to represent a right to additional physical inventory. An under-lift of production from a field is included in current receivables and an over-lift of production from a field is included in current liabilities.

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Production costs	347,832	292,252
Tariff and transportation expenses	43,266	39,414
Realised loss/(gain) on derivative contracts related to operating costs (see note 19)	5,418	(10,693)
Change in lifting position	(18,790)	62,868
Crude oil inventory movement	3,222	(561)
Depletion of oil and gas assets(i)	327,027	305,578
Other cost of operations(ii)	487,831	211,575
Business performance cost of sales	1,195,806	900,433
Unrealised losses/(gains) on derivative contracts related to operating costs(iii) (see note 19)	4,900	(472)
Movement in other provisions	-	7,673
Total cost of sales	1,200,706	907,634

(i) Includes $38.7 million (2021: $45.7 million) Kraken FPSO right-of-use asset depreciation charge and $15.8 million (2021: $14.3 million) of other right-of-use assets depreciation charge

(ii) Includes $452.8 million (2021: $199.6 million) of purchases and associated costs of third-party gas not required for injection activities at Magnus which is sold on

(iii) Unrealised gains and losses on derivative contracts are disclosed as fair value remeasurement in the income statement (see note 4)

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Staff costs (see note 5(f))	75,266	80,098
Depreciation(i)	6,222	7,492
Other general and administration costs	21,740	21,322
Recharge of costs to operations and joint venture partners	(95,675)	(108,549)
Total general and administration expenses	7,553	363

(i) Includes $3.4 million (2021: $4.0 million) right-of-use assets depreciation charge on buildings

(d) Other income

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Net foreign exchange gains	21,329	391
Change in decommissioning provisions (see note 23)	36,763	19,327
Rental income from office sublease	1,549	1,702
Change in Thistle decommissioning provisions (see note 23)	6,060	-
Other	10,546	9,570
Business performance other income	76,247	30,990
Fair value changes in contingent consideration (see note 22)	1,070	140,079
Other non-Business performance (see note 4)	6,636	22,568
Total other income	83,953	193,637

(e) Other expenses

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Change in Thistle decommissioning provisions (see note 23)	-	6,184
Other	2,810	1,094
Business performance other expenses	2,810	7,278
Fair value changes in contingent consideration (see note 22)	233,570	-
Other non-Business performance	-	3,832
Total other expenses	236,380	11,110

(f) Staff costs

Accounting policy

Short-term employee benefits, such as salaries, social premiums and holiday pay, are expensed when incurred.

The Group's pension obligations consist of defined contribution plans. The Group pays fixed contributions with no further payment obligations once the contributions have been paid. The amount charged to the Group income statement in respect of pension costs reflects the contributions payable in the year. Differences between contributions payable during the year and contributions actually paid are shown as either accrued liabilities or prepaid assets in the balance sheet.

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Wages and salaries	63,430	71,391
Social security costs	6,547	7,120
Defined contribution pension costs	4,968	5,464
Expense of share-based payments (see note 21)	4,719	6,351
Other staff costs	12,984	12,475
Total employee costs	92,648	102,801
Contractor costs	33,661	33,871
Total staff costs	126,309	136,672

General and administration staff costs (see note 5(c))	75,266	80,098
Non-general and administration costs	51,043	56,574
Total staff costs	126,309	136,672

The average number of persons, excluding contractors, employed by the Group during the year was 715, with 335 in the general and administration staff costs and 380 directly attributable to assets (2021: 734 of which 339 in general and administration and 395 directly attributable to assets). Compensation of key management personnel is disclosed in note 26 and in the remuneration report in the annual report.

(g) Auditor's remuneration

The following amounts for the year ended 31 December 2022 and for the comparative year ended 31 December 2021 were payable by the Group to Deloitte:

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Fees payable to the Company's auditor for the audit of the parent company and Group financial statements	1,064	847
The audit of the Company's subsidiaries	274	145
Total audit	1,338	992
Audit-related assurance services(i)	649	1,419
Total audit and audit-related assurance services	1,987	2,411
Tax services	-	-
Total auditor's remuneration	1,987	2,411

(i) Audit-related assurance services include the review of the Group's interim results and the Group's Bond refinancing activities

6. Finance costs/income

Accounting policy

Borrowing costs are recognised as interest payable within finance costs in accordance with the effective interest method.

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Finance costs:
Loan interest payable	14,906	20,206
Bond interest payable	62,260	69,085
Unwinding of discount on decommissioning provisions (see note 23)	16,995	15,856
Unwinding of discount on other provisions (see note 23)	777	1,061
Finance charges payable under leases (see note 24)	39,172	45,359
Amortisation of finance fees on loans and bonds	35,287	13,623
Other financial expenses(i)	6,830	4,261
Business performance finance expenses	176,227	169,451
Unwinding of discount on Magnus-related contingent consideration (see note 22)	36,410	58,395
Total finance costs	212,637	227,846
Finance income:
Bank interest receivable	1,816	228
Business performance finance income	1,816	228
Other financial income (see note 4)	2,148	-
Total finance income	3,964	228

(i) Includes unwinding of discount on Golden Eagle contingent consideration of $3.2 million (2021: $0.5 million). See note 22

7. Income tax

(a) Income tax

Accounting policy

Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities, based on tax rates and laws that are enacted or substantively enacted by the balance sheet date.

The Group's operations are subject to a number of specific tax rules which apply to exploration, development and production. 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 estimates and judgements including those required in calculating the effective tax rate. In considering the tax on exceptional items, the Group applies the appropriate statutory tax rate to each item to calculate the relevant tax charge on exceptional items.

Deferred tax is provided in full on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Group financial statements. However, deferred tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred tax is measured on an undiscounted basis using tax rates (and laws) that have been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred tax asset is realised or the deferred tax liability is settled. Deferred tax assets are recognised to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

The carrying amount of deferred income tax assets is reviewed at each balance sheet date. Deferred income tax assets and liabilities are offset only if a legal right exists to offset current tax assets against current tax liabilities, the deferred income taxes relate to the same taxation authority and that authority permits the Group to make a single net payment.

Production taxes

In addition to corporate income taxes, the Group's financial statements also include and disclose production taxes on net income determined from oil and gas production.

Production tax relates to Petroleum Revenue Tax ('PRT') within the UK and is accounted for under IAS 12 Income Taxes since it has the characteristics of an income tax as it is imposed under government authority and the amount payable is based on taxable profits of the relevant fields. Current and deferred PRT is provided on the same basis as described above for income taxes.

Investment allowance

The UK taxation regime provides for a reduction in ring-fence supplementary charge tax where investment in new or existing UK assets qualify for a relief known as investment allowance. Investment allowance must be activated by commercial production from the same field before it can be claimed. The Group has both unactivated and activated investment allowances which could reduce future supplementary charge taxation. The Group's policy is that investment allowance is recognised as a reduction in the charge to taxation in the years claimed.

Energy Profits Levy

On 14 July 2022, the Energy (Oil & Gas) profits Levy Act 2022 ('EPL') was enacted in the UK and applies an additional tax of 25% on the profits earned by oil and gas companies from the production of oil and gas on the United Kingdom Continental Shelf. The EPL will increase to a rate of 35% from 25% with effect from 1 January 2023. The increase in rate was substantively enacted on 30 November 2022. The end date was also extended from 31 December 2025 to 31 March 2028. The enactment of the EPL led to the additional recognition of deferred tax positions as at 31 December 2022, resulting in a net charge of $153.7 million (2021: nil).

The major components of income tax expense/(credit) are as follows:

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Current UK income tax
Current income tax charge	-	3,559
Adjustments in respect of current income tax of previous years	(243)	199
Current overseas income tax
Current income tax charge	19,017	18,050
Adjustments in respect of current income tax of previous years	(6,551)	(221)
UK Energy Profits Levy	72,147	-
Total current income tax	84,370	21,587
Deferred UK income tax
Relating to origination and reversal of temporary differences	1,784	(43,325)
Adjustments in respect of changes in tax rates	45	-
Adjustments in respect of deferred income tax of previous years	(4,668)	157
Deferred overseas income tax
Relating to origination and reversal of temporary differences	6,884	(5,320)
Adjustments in respect of deferred income tax of previous years	2,363	2,354
Deferred UK Energy Profits Levy	153,670	-
Total deferred income tax	160,078	(46,134)
Income tax expense/(credit) reported in profit or loss	244,448	(24,547)

(b) Reconciliation of total income tax charge

A reconciliation between the income tax charge and the product of accounting profit multiplied by the UK statutory tax rate is as follows:

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Profit/(loss) before tax	203,214	352,441
UK statutory tax rate applying to North Sea oil and gas activities of 40% (2021: 40%)	81,284	140,976
Supplementary corporation tax non-deductible expenditure	11,486	4,331
Petroleum revenue tax (net of income tax benefit)	-	2,548
Non-deductible expenditure/(income)(i)	47,951	(1,442)
North Sea tax reliefs	-	(113,593)
Tax in respect of non-ring-fence trade	8,892	23,378
Deferred tax asset (recognition)/impairment in respect of non-ring-fence trade	8,563	21,241
Deferred tax asset (recognition)/impairment in respect of ring-fence trade	(127,022)	(104,546)
Energy Profits Levy(ii)	225,817	-
Adjustments in respect of prior years	(9,098)	2,489
Overseas tax rate differences	(1,264)	(594)
Share-based payments	(1,345)	1,526
Other differences	(816)	(861)
At the effective income tax rate of 120% (2021: 7%)	244,448	(24,547)

(i) Predominantly in relation to non-qualifying expenditure relating to the initial recognition exemption utilised upon acquisition of Golden Eagle

(ii) Includes current EPL charge of $72.1 million and deferred EPL charge of $153.7 million

Deferred income tax relates to the following:

	Group balance sheet		(Credit)/charge for the year recognised in profit or loss
	2022 $'000	2021 $'000	2022 $'000	2021 $'000
Deferred tax liability
Accelerated capital allowances	963,816	768,630	195,185	(52,623)
	963,816	768,630
Deferred tax asset
Losses	(902,101)	(1,017,107)	114,996	(35,653)
Decommissioning liability	(238,624)	(286,045)	47,421	24,652
Other temporary differences	(362,565)	(165,030)	(197,524)	17,490
	(1,503,290)	(1,468,182)	160,078	(46,134)

Net deferred tax (assets)	(539,474)	(699,552)
Reflected in the balance sheet as follows:
Deferred tax assets	(705,808)	(702,970)
Deferred tax liabilities	166,334	3,418
Net deferred tax (assets)	(539,474)	(699,552)

Reconciliation of net deferred tax assets/(liabilities)

	2022 $'000	2021 $'000
At 1 January	699,552	653,418
Tax (expense)/income during the period recognised in profit or loss	(160,078)	46,134
At 31 December	539,474	699,552

(d) Tax losses

The Group's deferred tax assets at 31 December 2022 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. A $127.0 million tax credit has been recognised as an exceptional item, reflecting the reversal of the previous deferred tax asset derecognition. In accordance with IAS 12 Income Taxes, the Group assesses the recoverability of its deferred tax assets at each period end. Sensitivities have been run on the oil price assumption, with a 10% change being considered a reasonable possible change for the purposes of sensitivity analysis (see note 2). A 10% reduction in oil price would result in a deferred tax asset derecognition of $37.6 million and a 10% increase in oil price would not result in any change as the Group is currently recognising all UK tax losses (with the exception of those noted below).

The Group has unused UK mainstream corporation tax losses of $389.7 million (2021: $346.6 million) and ring-fence tax losses of $1,163.0 million (2021: $1,057.3 million) associated with the Bentley acquisition for which no deferred tax asset has been recognised at the balance sheet date as recovery of these losses is to be established. In addition, the Group has not recognised a deferred tax asset for the adjustment to bond valuations on the adoption of IFRS 9. The benefit of this deduction is taken over ten years, with a deduction of $2.2 million being taken in the current period and the remaining benefit of $10.7 million (2021: $12.9 million) remaining unrecognised.

The Group has unused Malaysian income tax losses of $14.3 million (2021: $15.7 million) arising in respect of the Tanjong Baram RSC for which no deferred tax asset has been recognised at the balance sheet date due to uncertainty of recovery of these losses.

No deferred tax has been provided on unremitted earnings of overseas subsidiaries. The Finance Act 2009 exempted foreign dividends from the scope of UK corporation tax where certain conditions are satisfied.

(e) Changes in legislation

In the budget statement on 3 March 2021, it was announced that the corporation tax rate will increase to 25% from 1 April 2023. This change is expected to have no impact.

8. Earnings per share

The calculation of earnings per share is based on the profit after tax and on the weighted average number of Ordinary shares in issue during the period. Diluted earnings per share is adjusted for the effects of Ordinary shares granted under the share-based payment plans, which are held in the Employee Benefit Trust, unless it has the effect of increasing the profit or decreasing the loss attributable to each share.

Basic and diluted earnings per share are calculated as follows:

	Profit/(loss) after tax		Weighted average number of Ordinary shares		Earnings per share
	Year ended 31 December		Year ended 31 December		Year ended 31 December
	2022 $'000	2021 $'000	2022 million	2021 million	2022 $	2021 $
Basic	(41,234)	376,988	1,855.0	1,736.4	(0.022)	0.217
Dilutive potential of Ordinary shares granted under share-based incentive schemes	-	-	39.2	24.7	-	-
Diluted(i)	(41,234)	376,988	1,894.2	1,761.1	(0.022)	0.214
Basic (excluding remeasurements and exceptional items)	212,346	220,284	1,855.0	1,736.4	0.114	0.127
Diluted (excluding remeasurements and exceptional items)(i)	212,346	220,284	1,894.2	1,761.1	0.112	0.125

(i) Potential Ordinary shares are not treated as dilutive when they would decrease a loss per share

9. Dividends paid and proposed

The Company paid no dividends during the year ended 31 December 2022 (2021: none). At 31 December 2022, there are no proposed dividends (2021: none).

10. Property, plant and equipment

Accounting policy

Property, plant and equipment is stated at cost less accumulated depreciation and accumulated impairment charges.

Cost

Cost comprises the purchase price or cost relating to development, including the construction, installation and completion of infrastructure facilities such as platforms, pipelines and development wells and any other costs directly attributable to making that asset capable of operating as intended by management. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

The carrying amount of an item of property, plant and equipment is derecognised on disposal or when no future economic benefits are expected from its use. The gain or loss arising from the derecognition of an item of property, plant and equipment is included in the other operating income or expense line item in the Group income statement when the asset is derecognised.

Development assets

Expenditure relating to development of assets including the construction, installation and completion of infrastructure facilities such as platforms, pipelines and development wells, is capitalised within property, plant and equipment.

Carry arrangements

Where amounts are paid on behalf of a carried party, these are capitalised. Where there is an obligation to make payments on behalf of a carried party and the timing and amount are uncertain, a provision is recognised. Where the payment is a fixed monetary amount, a financial liability is recognised.

Borrowing costs

Borrowing costs directly attributable to the construction of qualifying assets, which are assets that necessarily take a substantial period of time to prepare for their intended use, are capitalised during the development phase of the project until such time as the assets are substantially ready for their intended use.

Depletion and depreciation

Oil and gas assets are depleted, on a field-by-field basis, using the unit of production method based on entitlement to proven and probable reserves, taking account of estimated future development expenditure relating to those reserves. Changes in factors which affect unit of production calculations are dealt with prospectively. Depletion of oil and gas assets is taken through cost of sales.

Depreciation on other elements of property, plant and equipment is provided on a straight-line basis, and taken through general and administration expenses, at the following rates:

Office furniture and equipment Five years
Fixtures and fittings Ten years
Right-of-use assets* Lease term

* Excludes Kraken FPSO which is depleted using the unit of production method in accordance with the related oil and gas assets

Each asset's estimated useful life, residual value and method of depreciation is reviewed and adjusted if appropriate at each financial year end. No depreciation is charged on assets under construction.

Impairment of tangible and intangible assets (excluding goodwill)

At each balance sheet date, discounted cash flow models comprising asset-by-asset life of field projections and risks specific to assets, using Level 3 inputs (based on IFRS 13 fair value hierarchy), have been used to determine the recoverable amounts for each CGU. The life of a field depends on the interaction of a number of variables; see note 2 for further details. 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 Group's business plan. Oil price assumptions and discount rate assumptions used were as disclosed in note 2. 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 its recoverable amount. An impairment loss is recognised immediately in the Group income statement.

Where an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior years. A reversal of an impairment loss is recognised immediately in the Group income statement.

	Oil and gas assets $'000	Office furniture, fixtures and fittings $'000	Right-of-use assets (note 24) $'000	Total $'000
Cost:
At 1 January 2021	8,552,171	64,220	858,489	9,474,880
Acquisition	386,210	-	-	386,210
Additions	61,704	1,165	17,815	80,684
Change in decommissioning provision	(2,732)	-	-	(2,732)
Disposal	-	-	(8,411)	(8,411)
At 1 January 2022	8,997,353	65,385	867,893	9,930,631
Additions	116,415	1,936	28,394	146,745
Change in decommissioning provision	(75,917)	-	-	(75,917)
Disposal	-	-	(19,428)	(19,428)
At 31 December 2022	9,037,851	67,321	876,859	9,982,031
Accumulated depreciation, depletion and impairment:
At 1 January 2021	6,428,559	50,357	362,047	6,840,963
Charge for the year	245,645	3,472	63,953	313,070
Net impairment reversal for the year	(24,046)	-	(15,669)	(39,715)
Disposal	-	-	(5,831)	(5,831)
Other	146	-	-	146
At 1 January 2022	6,650,304	53,829	404,500	7,108,633
Charge for the year	272,588	2,796	57,864	333,248
Net impairment charge for the year	78,058	-	2,991	81,049
Disposal	-	-	(17,874)	(17,874)
At 31 December 2022	7,000,950	56,625	447,481	7,505,056
Net carrying amount:
At 31 December 2022	2,036,901	10,696	429,378	2,476,975
At 31 December 2021	2,347,049	11,556	463,393	2,821,998
At 1 January 2021	2,123,612	13,863	496,442	2,633,917

The amount of borrowing costs capitalised during the year ended 31 December 2022 was nil (2021: nil).

Impairments

Impairments to the Group's producing assets and reversals of impairments are set out in the table below:

	Impairment (charge)/reversal		Recoverable amount(i)
	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000	31 December 2022 $'000	31 December 2021 $'000
North Sea	(81,049)	39,715	1,448,391	1,496,219
Net pre-tax impairment reversal/(charge)	(81,049)	39,715

(i) Recoverable amount has been determined on a fair value less costs of disposal basis (see note 2 for further details of judgements, estimates and assumptions made in relation to impairments). The amounts disclosed above are in respect of assets where an impairment (or reversal) has been recorded. Assets which did not have any impairment or reversal are excluded from the amounts disclosed

For information on judgements, estimates and assumptions made in relation to impairments see 'Use of judgements, estimates and assumptions' within note 2.

The 2022 net impairment charge of $81.0 million relates to producing assets in the UK North Sea. Impairment charges were primarily driven by the introduction of EPL, changes in production profiles and an increased discount rate partially offset by an increase in EnQuest's oil price assumptions. The CGUs on which impairment charges relate were $9.6 million for Kraken, $34.9 million for GKA and Scolty/Crathes CGU, $36.1 million for Golden Eagle and $0.5 million for Alba.

The 2021 net impairment reversal of $39.7 million relates to producing assets in the UK North Sea. Impairment reversals were primarily driven by an increase in EnQuest's near-term future oil price assumptions. The CGUs on which impairment reversals relate were $53.7 million for Kraken and $6.1 million for Alba. In addition, impairment losses of $20.1 million were incurred relating to the GKA and Scolty/Crathes CGU, primarily as a result of forecast increased costs and lower production.

11. Goodwill

Accounting policy

Cost

Goodwill arising on a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition. If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, the gain is recognised in profit or loss.

Impairment of goodwill

Following initial recognition, goodwill is stated at cost less any accumulated impairment losses. In accordance with IAS 36 Impairment of Assets, goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the CGU to which the goodwill relates should be assessed.

For the purposes of impairment testing, goodwill acquired is allocated to the CGU that is expected to benefit from the synergies of the combination. Each unit or units to which goodwill is allocated represents the lowest level within the Group at which the goodwill is monitored for internal management purposes. Impairment is determined by assessing the recoverable amount of the CGU to which the goodwill relates. Where the recoverable amount of the CGU is less than the carrying amount of the CGU containing goodwill, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods. For information on significant estimates and judgements made in relation to impairments see Use of judgements, estimates and assumptions: recoverability of asset carrying values within note 2.

A summary of goodwill is presented below:

	2022 $'000	2021 $'000
Cost and net carrying amount
At 1 January	134,400	134,400
At 31 December	134,400	134,400

The majority of the goodwill, $94.6 million, relates to the 75% acquisition of the Magnus oil field and associated interests. The remaining goodwill balance arose from the acquisition of Stratic and PEDL in 2010 and the Greater Kittiwake Area asset in 2014.

Impairment testing of goodwill

Goodwill, which has been acquired through business combinations, has been allocated to the UK North Sea segment CGU, and this is therefore the lowest level at which goodwill is reviewed. The UK North Sea is a combination of oil and gas assets, as detailed within property, plant and equipment (note 10).

The recoverable amounts of the CGU and fields have been determined on a fair value less costs of disposal basis. See notes 2 and 10 for further details. An impairment charge of nil was taken in 2022 (2021: nil) based on a fair value less costs to dispose valuation of the North Sea CGU, as described above.

Sensitivity to changes in assumptions

The Group's recoverable value of assets is highly sensitive, inter alia, to oil price achieved and production volumes. A sensitivity has been run on the oil price assumption, with a 10% change being considered to be a reasonable possible change for the purposes of sensitivity analysis (see note 2). A 10% reduction in oil price would not result in an impairment (2021: 10% reduction would result in a net impairment of $54.7 million). A 25% reduction in oil price would fully impair goodwill (2021: 20%).

12. Intangible assets

Accounting policy

Exploration and appraisal assets

Exploration and appraisal assets have indefinite useful lives and are accounted for using the successful efforts method of accounting. Pre-licence costs are expensed in the period in which they are incurred. Expenditure directly associated with exploration, evaluation or appraisal activities is initially capitalised as an intangible asset. Such costs include the costs of acquiring an interest, appraisal well drilling costs, payments to contractors and an appropriate share of directly attributable overheads incurred during the evaluation phase. For such appraisal activity, which may require drilling of further wells, costs continue to be carried as an asset whilst related hydrocarbons are considered capable of commercial development. Such costs are subject to technical, commercial and management review to confirm the continued intent to develop, or otherwise extract value. When this is no longer the case, the costs are written off as exploration and evaluation expenses in the Group income statement. When exploration licences are relinquished without further development, any previous impairment loss is reversed and the carrying costs are written off through the Group income statement. When assets are declared part of a commercial development, related costs are transferred to property, plant and equipment. All intangible oil and gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the Group income statement.

During the year ended 31 December 2022, there was no impairment of historical exploration and appraisal expenditures (2021: nil).

Other intangibles

UK emissions allow ances ('UKAs') purchased to settle the Group's liability related to emissions are recognised on the balance sheet as an intangible asset at cost. The UKAs will be derecognised upon settling the liability with the respective regulator.

	Exploration and appraisal assets $'000	UK emissions allowances $'000	Total $'000
Cost:
At 1 January 2021	162,312	-	162,312
Additions	10,141	10,052	20,193
Write-off of relinquished licences previously impaired	(72)	-	(72)
At 1 January 2022	172,381	10,052	182,433
Additions	8,168	1,199	9,367
Write-off of relinquished licences previously impaired	(25,612)	-	(25,612)
Disposal	-	(10,052)	(10,052)
At 31 December 2022	154,937	1,199	156,136
Accumulated impairment:
At 1 January 2021 and 1 January 2022	(134,766)	-	(134,766)
Write-off of relinquished licences previously impaired	25,128	-	25,128
At 31 December 2022	(109,638)	-	(109,638)
Net carrying amount:
At 31 December 2022	45,299	1,199	46,498
At 31 December 2021	37,615	10,052	47,667
At 1 January 2021	27,546	-	27,546

13. Inventories

Accounting policy

Inventories of consumable well supplies and inventories of hydrocarbons are stated at the lower of cost and NRV, cost being determined on an average cost basis.

	2022 $'000	2021 $'000
Hydrocarbon inventories	19,613	22,835
Well supplies	56,805	50,188
	76,418	73,023

During 2022, a net loss of $4.0 million was recognised within cost of sales in the Group income statement relating to inventory (2021: net gain of $0.4 million).

The inventory valuation at 31 December 2022 is stated net of a provision of $38.9 million (2021: $43.2 million) to write down well supplies to their estimated net realisable value. During the year, a portion of the provided for well supplies was disposed of, resulting in a net charge to the income statement of $0.8 million (2021: $0.2 million).

14. Cash and cash equivalents

Accounting policy

Cash and cash equivalents includes cash at bank, cash in hand, outstanding bank overdrafts and highly liquid interest-bearing securities with original maturities of three months or fewer.

	2022 $'000	2021 $'000
Available cash	293,866	276,970
Restricted cash	7,745	9,691
Cash and cash equivalents	301,611	286,661

The carrying value of the Group's cash and cash equivalents is considered to be a reasonable approximation to their fair value due to their short-term maturities.

Restricted cash

Included within the cash balance at 31 December 2022 is restricted cash of $7.7 million which has been placed on deposit in relation to bank guarantees for the Group's Malaysian assets. Included within the cash balance at 31 December 2021 was restricted cash of $9.7 million. This included $8.2 million on deposit relating to bank guarantees for the Group's Malaysian assets and $1.5 million related to cash collateralised letters of credit.

15. Financial instruments and fair value measurement

Accounting policy

A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial instruments are recognised when the Group becomes a party to the contractual provisions of the financial instrument.

Financial assets and financial liabilities are offset and the net amount is reported in the Group balance sheet if there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis.

Financial assets

Financial assets are classified, at initial recognition, as amortised cost, fair value through other comprehensive income ('FVOCI'), or fair value through profit or loss ('FVPL'). The classification of financial assets at initial recognition depends on the financial assets' contractual cash flow characteristics and the Group's business model for managing them. The Group does not currently hold any financial assets at FVOCI, i.e. debt financial assets.

Financial assets are derecognised when the contractual rights to the cash flows from the financial asset expire, or when the financial asset and substantially all the risks and rewards are transferred.

Financial assets at amortised cost

Trade receivables, other receivables and joint operation receivables are measured initially at fair value and subsequently recorded at amortised cost, using the effective interest rate ('EIR') method, and are subject to impairment. Gains and losses are recognised in profit or loss when the asset is derecognised, modified or impaired and EIR amortisation is included within finance costs.

The Group measures financial assets at amortised cost if both of the following conditions are met:

· The financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and

· The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

Prepayments, which are not financial assets, are measured at historical cost.

Impairment of financial assets

The Group recognises a provision for expected credit loss ('ECL'), where material, for all financial assets held at the balance sheet date. ECLs are based on the difference between the contractual cash flows due to the Group, and the discounted actual cash flows that are expected to be received. Where there has been no significant increase in credit risk since initial recognition, the loss allowance is equal to 12-month expected credit losses. Where the increase in credit risk is considered significant, lifetime credit losses are provided. For trade receivables, a lifetime credit loss is recognised on initial recognition where material.

The provision rates are based on days past due for groupings of customer segments with similar loss patterns (i.e. by geographical region, product type, customer type and rating) and are based on historical credit loss experience, adjusted for forward-looking factors specific to the debtors and the economic environment. The Group evaluates the concentration of risk with respect to trade receivables and contract assets as low, as its customers are joint venture partners and there are no indications of change in risk. Generally, trade receivables are written off when they become past due for more than one year and are not subject to enforcement activity.

Financial liabilities

Financial liabilities are classified, at initial recognition, as amortised cost or at fair value through profit or loss.

Financial liabilities are derecognised when they are extinguished, discharged, cancelled or they expire. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as the derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised in the Group income statement.

Financial liabilities at amortised cost

Loans and borrowings, trade payables and other creditors are measured initially at fair value net of directly attributable transaction costs and subsequently recorded at amortised cost, using the EIR method. Loans and borrowings are interest bearing. Gains and losses are recognised in profit or loss when the liability is derecognised and EIR amortisation is included within finance costs.

Financial instruments at fair value through profit or loss

The Group holds derivative financial instruments classified as held for trading, not designated as effective hedging instruments. The derivative financial instruments include forward currency contracts and commodity contracts, to address the respective risks; see note 27. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative.

Financial instruments at FVPL are carried in the Group balance sheet at fair value, with net changes in fair value recognised in the Group income statement. Unrealised mark-to-market changes in the remeasurement of open derivative contracts at each period end are recognised within remeasurements, with the recycling of realised amounts from remeasurements into Business performance income when a derivative instrument matures. Option premium received or paid for commodity derivatives are recognised in remeasurements.

Financial assets with cash flows that are not solely payments of principal and interest are classified and measured at fair value through profit or loss, irrespective of the business model. All financial assets not classified as measured at amortised cost or FVOCI as described above are measured at FVPL. Financial instruments with embedded derivatives are considered in their entirety when determining whether their cash flows are solely payment of principal and interest.

The Group also holds contingent consideration (see note 22) and a listed equity investment (see note 19). The movements of both are recognised within remeasurements in the Group income statement.

Fair value measurement

The following table provides the fair value measurement hierarchy of the Group's assets and liabilities:

31 December 2022	Notes	Total $'000	Quoted prices in active markets (Level 1) $'000	Significant observable inputs (Level 2) $'000	Significant unobservable inputs (Level 3) $'000
Financial assets measured at fair value:
Derivative financial assets measured at FVPL
Gas commodity contracts		4,705	-	4,705	-
Other financial assets measured at FVPL
Quoted equity shares		6	6	-	-
Total financial assets measured at fair value		4,711	6	4,705	-
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Oil commodity derivative contracts	19	46,537	-	46,537	-
Forward UKA contracts	19	4,429	-	4,429	-
Other financial liabilities measured at FVPL
Contingent consideration	22	636,875	-	-	636,875
Total liabilities measured at fair value		687,841	-	50,966	636,875
Liabilities measured at amortised cost for which fair values are disclosed below:
Interest-bearing loans and borrowings	18	417,967	-	-	417,967
Obligations under leases	24	482,066	-	-	482,066
Retail Bond 7.00%	18	133,535	133,535	-	-
Retail Bond 9.00%	18	153,754	153,754	-	-
High yield bond 11.625%	18	297,528	297,528	-	-
Total liabilities measured at amortised cost for which fair values are disclosed		1,484,850	584,817	-	900,033

31 December 2021	Notes	Total $'000	Quoted prices in active markets (Level 1) $'000	Significant observable inputs (Level 2) $'000	Significant unobservable inputs (Level 3) $'000
Financial assets measured at fair value:
Derivative financial assets measured at FVPL
Forward UKA contracts		90	-	90	-
Forward foreign currency contracts		382	-	382	-
Other financial assets measured at FVPL
Quoted equity shares		6	6	-	-
Total financial assets measured at fair value		478	6	472	-
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Oil commodity derivative contracts	19	55,247	-	55,247	-
Other financial liabilities measured at FVPL
Contingent consideration	22	410,778	-	-	410,778
Total liabilities measured at fair value		466,025	-	55,247	410,778
Liabilities measured at amortised cost for which fair values are disclosed below:
Interest-bearing loans and borrowings	18	424,864	-	-	424,864
Obligations under leases	24	570,781	-	-	570,781
Retail bond 7.00%	18	244,387	244,387	-	-
High yield bond 7.00%	18	773,499	773,499	-	-
Total liabilities measured at amortised cost for which fair values are disclosed		2,013,531	1,017,886	-	995,645

Fair value hierarchy

All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, based on the lowest level input that is significant to the fair value measurement as a whole, as follows:

Level 1: Quoted (unadjusted) market prices in active markets for identical assets or liabilities;
Level 2: Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly (i.e. as prices) or indirectly (i.e. derived from prices) observable;
Level 3: Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable.

Derivative financial instruments are valued by counterparties, with the valuations reviewed internally and corroborated with readily available market data (Level 2). Contingent consideration is measured at FVPL using the Level 3 valuation processes disclosed in note 22. There have been no transfers between Level 1 and Level 2 during the period (2021: no transfers).

For the financial liabilities measured at amortised cost but for which fair value disclosures are required, the fair value of the bonds classified as Level 1 was derived from quoted prices for that financial instrument. Both interest-bearing loans and borrowings and obligations under finance leases were calculated using the discounted cash flow method to capture the present value (Level 3).

16. Trade and other receivables

	2022 $'000	2021 $'000
Current
Trade receivables	69,508	94,992
Joint venture receivables	95,854	68,157
Under-lift position	26,474	35,769
Other receivables	4,141	11,703
	195,977	210,621
Prepayments and accrued income	80,386	85,447
	276,363	296,068

The carrying values of the Group's trade, joint venture and other receivables as stated above are considered to be a reasonable approximation to their fair value largely due to their short-term maturities. Under-lift is valued at the lower of cost or NRV at the prevailing balance sheet date (note 5(b)).

Trade receivables are non-interest-bearing and are generally on 15 to 30-day terms. Joint venture receivables relate to amounts billable to, or recoverable from, joint venture partners. Receivables are reported net of any ECL with no losses recognised as at 31 December 2022 or 2021.

17. Trade and other payables

	2022 $'000	2021 $'000
Current
Trade payables	34,661	49,701
Accrued expenses	349,668	297,744
Over-lift position	25,658	53,742
Joint venture creditors	11,957	10,852
VAT payable	4,167	7,561
Other payables	536	944
	426,647	420,544

The carrying value of the Group's trade and other payables as stated above is considered to be a reasonable approximation to their fair value largely due to the short-term maturities. Certain trade and other payables will be settled in currencies other than the reporting currency of the Group, mainly in Sterling. Trade payables are normally non-interest-bearing and settled on terms of between 10 and 30 days.

Accrued expenses include accruals for capital and operating expenditure in relation to the oil and gas assets and interest accruals.

18. Loans and borrowings

	2022 $'000	2021 $'000
Borrowings	413,358	401,614
Bonds	586,930	1,081,596
	1,000,288	1,483,210

(a) Borrowings

The Group's borrowings are carried at amortised cost as follows:

	2022			2021
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
RBL facility	400,000	(4,609)	395,391	415,000	(23,250)	391,750
SVT working capital facility	12,275	-	12,275	9,864	-	9,864
Vendor loan facility	5,692	-	5,692	-	-	-
Total borrowings	417,967	(4,609)	413,358	424,864	(23,250)	401,614
Due within one year			131,936			210,505
Due after more than one year			281,422			191,109
Total borrowings			413,358			401,614

See liquidity risk - note 27 for the timing of cash outflows relating to loans and borrowings.

Reserve Based Lending facility

In October 2022, the Group agreed an amended and restated RBL facility with commitments of $500.0 million, reducing in accordance with an amortisation schedule, a sub limit for drawings in the form of Letters of Credit of $75.0 million and a standard accordion facility which allowed the Group to increase commitments by an amount of up to $300.0 million on no more than three occasions. The maturity of the new facility is April 2027. Funds can only be drawn under the RBL to a maximum amount of the lesser of (i) the total commitments and (ii) the borrowing base amount. Interest accrued at 4.00% plus a combination of an agreed credit adjustment spread and Secured Overnight Financing Rate 'SOFR'. The amended and restated RBL facility replaced the Group's previous facility, which was signed on 11 June 2021 and accrued interest at 4.25% plus a combination of a fixed rate based on the interest period and SOFR (2021: 4.25% plus USD LIBOR). During 2022, EnQuest fully repaid the previous RBL facility prior to agreeing the amended and restated RBL facility.

As at 31 December 2022, the carrying value of the facility was $395.4 million (2021: $391.8 million), comprising the principal of $400.0 million out of commitments of $500.0 million (2021: $415.0 million) and unamortised fees of $4.6 million (2021: $23.3 million).

At 31 December 2022, after allowing for letter of credit utilisation of $52.7 million (2021: $53.0 million), $47.3 million (2021: $32.0 million) remained available for drawdown under the RBL.

SVT working capital facility

On 1 December 2020, EnQuest extended, for a further three years, the £42.0 million revolving loan facility with a joint operator partner to fund the short-term working capital cash requirements of SVT and associated interests. The facility is guaranteed by BP EOC Limited until the earlier of a0 the date on which production from Magnus permanently ceases; or b) if the operating agreements for both SVT and associated infrastructure are amended to allow for cash calling. The facility is able to be drawn down against, in instalments, and accrues interest at 1.0% per annum plus GBP Sterling Over Night Index Average 'SONIA'.

Vendor loan facility

In December 2022, the Group agreed a facility with a third party vendor refinancing the payment of existing invoices up to an amount of £7.5 million. At 31 December 2022, an amount of £4.7 million was drawn down on the facility repayable in June 2023. Interest is payable monthly at a rate of 8.00% per annum.

(b) Bonds

The Group's bonds are carried at amortised cost as follows:

	2022			2021
	Principal $'000	Fees and discount $'000	Total $'000	Principal $'000	Fees and discount $'000	Total $'000
High yield bond 7.00%	-	-	-	827,166	(1,725)	825,441
High yield bond 11.625%	305,000	(13,815)	291,185	-	-	-
Retail bond 7.00%	134,544	-	134,544	256,574	(419)	256,155
Retail bond 9.00%	161,201	-	161,201	-	-	-
Total	600,745	(13,815)	586,930	1,083,740	(2,144)	1,081,596
Due within one year	134,544	-	134,544	-	-	-
Due after more than one year	466,201	(13,815)	452,386	1,083,740	(2,144)	1,081,596
Total	600,745	(13,815)	586,930	1,083,740	(2,144)	1,081,596

High yield bond 7.00%

In October 2022, the Group redeemed the full outstanding balance of $792.3 million ahead of its maturity in October 2023. At 31 December 2021, the carrying value of the bond was $825.4 million. This included bond principal of $827.2 million less unamortised fees of $1.7 million. In 2021, the high yield bond did not include accrued interest of $12.2 million, which is reported within trade and other payables.

High yield bond 11.625%

In October 2022, the Group concluded an offer of $305.0 million for a US Dollar high yield bond. The notes accrue a fixed coupon of 11.625% payable semi-annually in arrears with a maturity date of November 2027.

The above carrying value of the bond as at 31 December 2022 is $291.2 million. This includes bond principal of $305.0 million less the original issue discount ('OID') of $4.2 million and unamortised fees of $9.6 million. The high yield bond does not include accrued interest of $6.5 million, which is reported within trade and other payables. The fair value of the high yield bond 11.625% is disclosed in note 15.

Retail bond 7.00%

In 2013, the Group issued a £155.0 million retail bond. On 21 November 2016, the retail bond was amended pursuant to a scheme of arrangement whereby all existing notes were exchanged for new notes, accruing a fixed coupon of 7.00% payable semi-annually in arrears. The interest is only payable in cash if the 'Cash Payment Condition' is satisfied, being the average of the Daily Brent Oil Prices during the period of six calendar months immediately preceding the 'Cash Payment Condition Determination Date' is equal to or above $65/bbl. The 'Cash Payment Condition Determination Date' is the date falling one calendar month prior to the relevant interest payment date. If the 'Cash Payment Condition' is not satisfied, interest will not be paid in cash but instead will be capitalised and satisfied through the issue of additional retail notes ('Additional Retail Notes').

On 27 April 2022, following a successful partial exchange and cash offer, £79.3 million of the retail bond 7.00% were exchanged for the retail bond 9.00%. This resulted in a reduction of principal by $104.4 million.

The above carrying value of the bond as at 31 December 2022 is $134.5 million (2021: $256.2 million). This includes bond principal of $134.5 million (2021: $256.6 million) less unamortised fees of nil (2021: $0.4 million), with the prior unamortised amount of fees recognised in the income statement in 2022 upon completion of the refinancing via the partial exchange and cash offer noted above. The retail bond does not include accrued interest of $2.6 million (2021: $6.2 million), which is reported within trade and other payables. The fair value of the retail bond 7.00% is disclosed in note 15.

Retail bond 9.00%

On 27 April 2022, the Group issued a new 9.00% retail bond following a successful partial exchange and cash offer. The principal of the retail bond 9.00% raised by the partial exchange and cash offer totalled £133.3 million. The notes accrue a fixed coupon of 9.00% payable semi-annually in arrears and are due to mature in October 2027.

The above carrying value of the bond as at 31 December 2022 is $161.2 million. All fees associated with this offer were recognised in the income statement in 2022. The retail bond 9.00% does not include accrued interest of $3.6 million, which is reported within trade and other payables. The fair value of the retail bond 9.00% is disclosed in note 15.

19. Other financial assets and financial liabilities

(a) Summary as at year end

	2022		2021
	Assets $'000	Liabilities $'000	Assets $'000	Liabilities $'000
Fair value through profit or loss:
Derivative commodity contracts	4,705	46,537	-	55,245
Derivative foreign exchange contracts	-	-	382	-
Commodity futures	-	-	-	2
Derivative UKAs contracts	-	4,429	90	-
Total current	4,705	50,966	472	55,247
Fair value through profit or loss:
Quoted equity shares	6	-	6	-
Total non-current	6	-	6	-

(b) Income statement impact

The income/(expense) recognised for derivatives are as follows:

Year ended 31 December 2022	Revenue and other operating income		Cost of sales
Year ended 31 December 2022	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	(204,943)	20,401	-	-
Commodity swaps	(86)	(5,928)	-	-
Commodity futures	1,288	2	-	-
Foreign exchange contracts	-	-	(5,158)	(381)
UKA contracts	-	-	(260)	(4,519)
	(203,741)	14,475	(5,418)	(4,900)

Year ended 31 December 2021	Revenue and other operating income		Cost of sales
Year ended 31 December 2021	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	(62,016)	(55,570)	-	-
Commodity swaps	(4,258)	1,121	-	-
Commodity futures	985	(2)	-	-
Foreign exchange contracts	-	-	(4)	382
UKA contracts	-	-	10,697	90
	(65,289)	(54,451)	10,693	472

The Group uses derivative financial instruments to manage its exposure to the oil price, including put and call options, swap contracts and futures.

For the year ended 31 December 2022, losses totalling $189.3 million (2021: losses of $119.7 million) were recognised in respect of commodity contracts designated as FVPL. This included losses totalling $203.7 million (2021: losses of $65.3 million) realised on contracts that matured during the year, and mark-to-market unrealised gains totalling $14.5 million (2021: losses of $54.5 million). Of the realised amounts recognised during the year, a loss of $1.3 million (2021: losses of $1.0 million) was realised in Business performance revenue in respect of the premium expense received on sale of these options.

The mark-to-market value of the Group's open commodity contracts as at 31 December 2022 was a net liability of $41.8 million (2021: liability of $55.2 million).

(d) Foreign currency contracts

The Group enters into a variety of foreign currency contracts, primarily in relation to Sterling. During the year ended 31 December 2022, losses totalling $5.4 million (2021: gains of $0.4 million) were recognised in the Group income statement. This included realised losses totalling $5.2 million (2021: losses of $0.1 million) on contracts that matured in the year.

The mark-to-market value of the Group's open contracts as at 31 December 2022 was nil (2021: $0.4 million).

(e) UK emissions allow ance forward contracts

The Group enters into forward contracts for the purchase of UKAs to manage its exposure to price. During 2021, a number of open contracts were closed out early resulting in gains totalling $10.8 million, including realised gains totalling $10.7 million that matured in the year. The result of this was that the Group is required to account for UKA forwards as derivatives. During the year ended 31 December 2022, no open contracts were closed out early.

The mark-to-market value of the Group's open contracts as at 31 December 2022 was $4.4 million (2021: $0.1 million).

(f) Other receivables

	2022 $'000	2021 $'000
At 1 January	6	7
Change in fair value	-	(1)
At 31 December	6	6

Non-current	6	6
	6	6

20. Share capital and premium

Accounting policy

Share capital and share premium

The balance classified as equity share capital includes the total net proceeds (both nominal value and share premium) on issue of registered share capital of the parent company. Share issue costs associated with the issuance of new equity are treated as a direct reduction of proceeds. The share capital comprises only one class of Ordinary share. Each Ordinary share carries an equal voting right and right to a dividend.

Retained earnings

Retained earnings contain the accumulated profits/(losses) of the Group.

Share-based payments reserve

Equity-settled share-based payment transactions are measured at the fair value of the services received, and the corresponding increase in equity is recorded. EnQuest PLC shares held by the Group in the Employee Benefit Trust are recognised at cost and are deducted from the share-based payments reserve. Consideration received for the sale of such shares is also recognised in equity, with any difference between the proceeds from the sale and the original cost being taken to reserves. No gain or loss is recognised in the Group income statement on the purchase, sale, issue or cancellation of equity shares.

Authorised, issued and fully paid

Ordinary

shares of
£0.05 each

Number

capital

$'000

premium

$'000

Total

$'000

At 1 January 2022 and 31 December 2022

1,885,924,339

131,650

260,546

392,196

At 31 December 2022, there were 21,663,181 shares held by the Employee Benefit Trust (2021: 39,718,323). The movement in the year was due to shares used to satisfy awards made under the Company's share-based incentive schemes.

21. Share-based payment plans

Accounting policy

Eligible employees (including Executive Directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares of EnQuest PLC.

Information on these plans for Executive Directors is shown in the Directors' Remuneration Report in the annual report.

The cost of these equity-settled transactions is measured by reference to the fair value at the date on which they are granted. The fair value of awards is calculated in reference to the scheme rules at the market value, being the average middle market quotation of a share for the three immediately preceding dealing days as derived from the Daily Official List of the London Stock Exchange, provided such dealing days do not fall within any period when dealings in shares are prohibited because of any dealing restriction.

The cost of equity-settled transactions is recognised over the vesting period in which the relevant employees become fully entitled to the award. The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The Group income statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

In valuing the transactions, no account is taken of any service or performance conditions, other than conditions linked to the price of the shares of EnQuest PLC (market conditions) or 'non-vesting' conditions, if applicable. No expense is recognised for awards that do not ultimately vest, except for awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions are satisfied. Equity awards cancelled are treated as vesting immediately on the date of cancellation, and any expense not previously recognised for the award at that date is recognised in the Group income statement.

The Group operates a number of equity-settled employee share plans under which share units are granted to the Group's senior leaders and certain other employees. These plans typically have a three-year performance or restricted period. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons.

The share-based payment expense recognised for each scheme was as follows:

	2022 $'000	2021 $'000
Performance Share Plan	3,264	5,241
Other performance share plans	261	135
Sharesave Plan	1,194	975
	4,719	6,351

The following table shows the number of shares potentially issuable under equity-settled employee share plans, including the number of options outstanding and the number of options exercisable at the end of each year.

Share plans	2022 Number	2021 Number
Outstanding at 1 January	125,493,995	110,263,670
Granted during the year	17,368,011	35,552,383
Exercised during the year	(15,712,039)	(8,056,525)
Forfeited during the year	(24,878,703)	(12,265,533)
Outstanding at 31 December	102,271,264	125,493,995
Exercisable at 31 December	10,490,719	14,249,920

In addition, the Group operates an approved savings-related share option scheme (the Sharesave Plan). The plan is based on eligible employees being granted options and their agreement to opening a Sharesave account with a nominated savings carrier and to save over a specified period, either three or five years. The right to exercise the option is at the employee's discretion at the end of the period previously chosen, for a period of six months.

The following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of options outstanding, the number of options exercisable at the end of each year and the corresponding weighted average exercise prices.

	2022		2021
Share options	Number	Weighted average exercise price $	Number	Weighted average exercise price $
Outstanding at 1 January	37,518,927	0.14	42,383,654	0.13
Granted during the year	1,292,788	0.32	1,370,748	0.25
Exercised during the year	(2,150,313)	0.17	(885,646)	0.10
Forfeited during the year	(3,353,153)	0.14	(5,349,829)	0.15
Outstanding at 31 December	33,308,249	0.14	37,518,927	0.14
Exercisable at 31 December	445,318	0.17	422,981	0.16

22. Contingent consideration

Accounting policy

When the consideration transferred by the Group in a business combination includes a contingent consideration arrangement, the contingent consideration is measured at its acquisition-date fair value and included as part of the consideration transferred in a business combination. 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 depicted below is remeasured to fair value at subsequent reporting dates with changes in fair value recognised in profit or loss. Contingent consideration that is classified as equity if any, is not remeasured at subsequent reporting dates and its subsequent settlement is accounted for within equity.

Contingent consideration is discounted at a risk free rate combined with a risk premium, calculated in alignment with IFRS 13 and the unwinding of the discount is presented within finance costs.

Any contingent consideration included in the consideration payable for an asset acquisition is recorded at fair value at the date of acquisition and included in the initial measurement of cost. Subsequent measurement changes relating to the variable consideration are capitalised as part of the asset value if it is probable that future economic benefits associated with the asset will flow to the Group and can be measured reliably.

	Magnus 75% $'000	Magnus decommissioning-linked liability $'000	Golden Eagle $'000	Total $'000
At 31 December 2021	344,627	20,976	45,175	410,778
Change in fair value (see note 5(d))	233,570	(1,070)	-	232,500
Unwinding of discount (see note 6)	34,463	1,947	3,162	39,572
Utilisation	(45,975)	-	-	(45,975)
At 31 December 2022	566,685	21,853	48,337	636,875
Classified as:
Current	72,264	2,597	48,337	123,198
Non-current	494,421	19,256	-	513,677
	566,685	21,853	48,337	636,875

75% Magnus acquisition contingent consideration

On 1 December 2018, EnQuest completed the acquisition of the additional 75% interest in the Magnus oil field ('Magnus') and associated interests (collectively the 'Transaction assets') which was part funded through a vendor loan and profit share arrangement with bp.

The consideration for the acquisition was $300.0 million, consisting of $100.0 million cash contribution, paid from the funds received through the rights issue undertaken in October 2018, and $200.0 million deferred consideration financed by bp. The deferred consideration financed by bp was fully settled in June 2021. The consideration also included a contingent profit-sharing arrangement whereby EnQuest and bp share the net cash flow generated by the 75% interest on a 50:50 basis, subject to a cap of $1.0 billion received by bp. Together, the deferred consideration and contingent profit-sharing arrangement are known as contingent consideration. The contingent consideration is a financial liability classified as measured at fair value through profit or loss. The fair value of contingent consideration has been determined by calculating the present value of the future expected cash flows expected to be paid and is considered a Level 3 valuation under the fair value hierarchy. Future cash flows are estimated based on inputs including future oil prices, production volumes and operating costs. Oil price assumptions and discount rate assumptions used were as disclosed in Use of judgements, estimates and assumptions within note 2. The contingent consideration was fair valued at 31 December 2022, which resulted in an increase in fair value of $233.6 million (2021: decrease of $145.3 million). The increase in fair value in 2022 is a result of the Group's higher long-term oil price assumptions and changes in asset profiles and cost assumptions. The decrease in 2021 reflected revised operating cost assumptions. The fair value accounting effect and finance costs of $34.5 million (2021: $57.0 million) on the contingent consideration were recognised through remeasurements and exceptional items in the Group income statement. The contingent profit-sharing arrangement cap of $1.0 billion has been met in 2022 in the present value calculations (2021: cap was not met). Within the statement of cash flows, the profit share element of the repayment, $46.0 million (2021: $1.0 million) is disclosed separately under investing activities; in 2021, the repayment of the vendor loan of $73.7 million was disclosed under financing activities; and the interest paid on the vendor loan of $6.2 million was included within interest paid under financing activities. At 31 December 2022, the contingent consideration for Magnus was $566.7 million (31 December 2021: $344.6 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 discount rate, the oil price and the interrelationship with production and the profit-share arrangement. A 1.0% reduction in the discount rate applied, which is considered a reasonably possible change given the prevailing macroeconomic conditions, would increase contingent consideration by $23.0 million. A 1.0% increase would decrease contingent consideration by $21.5 million. As the profit-sharing cap of $1.0 billion has been met in 2022 in the present value calculations, sensitivity analysis has only been undertaken on a reduction in the price assumptions of 10%, which is considered to be a reasonably possible change. This results in a reduction of $73.6 million to the contingent consideration (2021: reduction of $85.1 million and increase of $85.1 million, respectively). The change in value represents a change in timing of cash flows.

The payment of contingent consideration is limited to cash flows generated from Magnus. Therefore, no contingent consideration is payable if insufficient cash flows are generated over and above the requirements to operate the asset. By reference to the conditions existing at 31 December 2022, the maturity analysis of the contingent consideration is disclosed in Risk management and financial instruments: liquidity risk (note 27).

Magnus decommissioning-linked contingent consideration

As part of the Magnus and associated interests acquisition, bp retained the decommissioning liability in respect of the existing wells and infrastructure and EnQuest agreed to pay additional consideration in relation to the management of the physical decommissioning costs of Magnus. At 31 December 2022, the amount due to bp calculated on an after-tax basis by reference to 30% of bp's decommissioning costs on Magnus was $21.9 million (2021: $21.0 million). Any reasonably possible change in assumptions would not have a material impact on the provision.

Golden Eagle contingent consideration

On 22 October 2021, the Group completed the acquisition of the entire 26.69% non-operated working interest in the Golden Eagle Area Development, comprising the producing Golden Eagle, Peregrine and Solitaire fields. The consideration for the acquisition included an amount that was contingent on the average oil price between July 2021 and June 2023. The contingent consideration is payable in the second half of 2023, if between July 2021 and June 2023 the Dated Brent average crude price equals or exceeds $55/bbl, upon which $25.0 million is payable, or if the Dated Brent average crude price equals or exceeds $65/bbl, upon which $50.0 million is payable. The contingent consideration liability is discounted at 7.00%, based on an appropriate credit risk premium at the time of acquisition, and is calculated principally based on the oil price assumptions as disclosed in note 2. At 31 December 2022, the contingent consideration was valued at $48.3 million (2021: $45.2 million). Any reasonably possible change in assumptions would not have a material impact on the provision.

23. Provisions

Accounting policy

Decommissioning

Provision for future decommissioning costs is made in full when the Group has an obligation: to dismantle and remove a facility or an item of plant; to restore the site on which it is located; and when a reasonable estimate of that liability can be made. The Group's provision primarily relates to the future decommissioning of production facilities and pipelines.

A decommissioning asset and liability are recognised, within property, plant and equipment and provisions respectively, at the present value of the estimated future decommissioning costs. The decommissioning asset is amortised over the life of the underlying asset on a unit of production basis over proven and probable reserves, included within depletion in the Group income statement. Any change in the present value of estimated future decommissioning costs is reflected as an adjustment to the provision and the oil and gas asset for producing assets. For assets that have ceased production, the change in estimate is reflected as an adjustment to the provision and the Group Income Statement, via other income or expense. The unwinding of the decommissioning liability is included under finance costs in the Group income statement.

These provisions have been created based on internal and third-party estimates. Assumptions based on the current economic environment have been made which management believes are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required, which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning liabilities is likely to depend on the dates when the fields cease to be economically viable. This in turn depends on future oil prices, which are inherently uncertain. See Use of judgements, estimates and assumptions: provisions within note 2.

Other

Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and a reliable estimate can be made of the amount of the obligation.

	Decommissioning provision $'000	Thistle decommissioning provision $'000	Other provisions $'000	Total $'000
At 31 December 2021	835,721	43,930	15,291	894,942
Additions during the year(i)	2,814	-	1,423	4,237
Changes in estimates(i)	(115,493)	(6,060)	(1,373)	(122,926)
Unwinding of discount	16,995	777	-	17,772
Utilisation	(48,452)	(5,832)	(962)	(55,246)
Foreign exchange	(1)	(95)	(1,013)	(1,109)
At 31 December 2022	691,584	32,720	13,366	737,670
Classified as:
Current	47,883	9,086	13,366	70,335
Non-current	643,701	23,634	-	667,335
	691,584	32,720	13,366	737,670

(i) Includes $36.8 million relating to assets in decommissioning disclosed in note 5(d) and $75.9 million related to producing assets disclosed in note 10

Decommissioning provision

The Group's total provision represents the present value of decommissioning costs which are expected to be incurred up to 2048, assuming no further development of the Group's assets. Additions during the year relate to the decommissioning provision recognised due to drilling of new wells in Magnus and Golden Eagle. Changes in estimates during the year primarily reflect an increase in the Group's discount rate to 3.5% (2021: 2.0%) as detailed in note 2, partially offset by the net effect of underlying increases in cost estimates. At 31 December 2022, an estimated $407.0 million is expected to be utilised between one and five years (2021: $409.6 million), $67.6 million within six to ten years (2021: $81.4 million), and the remainder in later periods.

The Group enters into surety bonds principally to provide security for its decommissioning obligations. The surety bond facilities which expired in December 2021 were renewed for 12 months, subject to ongoing compliance with the terms of the Group's borrowings. At 31 December 2022, the Group held surety bonds totalling $227.6 million (2021: $240.8 million).

Thistle decommissioning provision

In 2017, EnQuest had the option to receive $50.0 million from bp in exchange for undertaking the management of the physical decommissioning activities for Thistle and Deveron and making payments by reference to 7.5% of bp's share of decommissioning costs of Thistle and Deveron fields. The option was exercised in full during 2018 and the liability recognised within provisions. At 31 December 2022, the amount due to bp by reference to 7.5% of bp's decommissioning costs on Thistle and Deveron was $32.7 million (2021: $43.9 million). For the year ended 31 December 2022, change in estimates of $6.1 million are included within other income (2021: $6.2 million other expenses) and unwinding of discount of $0.8 million is included within finance income (2021: $1.1 million).

Other provisions

During 2020, a riser at the Seligi Alpha platform which provides gas lift and injection to the Seligi Bravo platform detached. A provision with respect to required repairs to remedy the damage caused was established. During 2022, $0.3 million was utilised with a foreign exchange impact of $0.5 million. At 31 December 2022, the provision was $0.7 million (31 December 2021: $1.5 million).

During 2021, the Group recognised $8.2 million in relation to disputes with third-party contractors. In 2022, one dispute was settled for $0.5 million and the other dispute is ongoing. At 31 December 2022, the provision was $7.5 million (31 December 2021: $8.2 million). The Group expects the dispute to be settled in 2023.

24. Leases

Accounting policy

As a lessee

The Group recognises a right-of-use asset and a lease liability at the lease commencement date.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted by using the rate implicit in the lease, or, if that rate cannot be readily determined, the Group uses its incremental borrowing rate.

The incremental borrowing rate is the rate that the Group would have to pay for a loan of a similar term, and with similar security, to obtain an asset of similar value. The incremental borrowing rate is determined based on a series of inputs including: the term, the risk-free rate based on government bond rates and a credit risk adjustment based on EnQuest bond yields.

Lease payments included in the measurement of the lease liability comprise:

· fixed lease payments (including in-substance fixed payments), less any lease incentives;

· variable lease payments that depend on an index or rate, initially measured using the index or rate at the commencement date;

· the exercise price of purchase options, if the lessee is reasonably certain to exercise the options; and

· payments of penalties for terminating the lease, if the lease term reflects the exercise of an option to terminate the lease.

The lease liability is subsequently recorded at amortised cost, using the effective interest rate method. The liability is remeasured when there is a change in future lease payments arising from a change in an index or rate or if the Group changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero. The Group did not make any such adjustments during the periods presented.

The right-of-use asset is measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received. Right-of-use assets are depreciated over the shorter period of lease term and useful life of the underlying asset. If a lease transfers ownership of the underlying asset or the cost of the right-of-use asset reflects that the Group expects to exercise a purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset. The depreciation starts at the commencement date of the lease.

The Group applies the short-term lease recognition exemption to those leases that have a lease term of 12 months or less from the commencement date. It also applies the low-value assets recognition exemption to leases of assets below £5,000. Lease payments on short-term leases and leases of low-value assets are recognised as an expense on a straight-line basis over the lease term.

The Group applies IAS 36 Impairment of Assets to determine whether a right-of-use asset is impaired and accounts for any identified impairment loss as described in the 'property, plant and equipment' policy.

Variable rents that do not depend on an index or rate are not included in the measurement of the lease liability and the right-of-use asset. The related payments are recognised as an expense in the period in which the event or condition that triggers those payments occurs and are included within 'cost of sales' or 'general and administration expenses' in the Group income statement.

For leases within joint ventures, the Group assesses on a lease-by-lease basis the facts and circumstances. This relates mainly to leases of vessels. Where all parties to a joint operation jointly have the right to control the use of the identified asset and all parties have a legal obligation to make lease payments to the lessor, the Group's share of the right-of-use asset and its share of the lease liability will be recognised on the Group balance sheet. This may arise in cases where the lease is signed by all parties to the joint operation or the joint operation partners are named within the lease. However, in cases where EnQuest is the only party with the legal obligation to make lease payments to the lessor, the full lease liability and right-of-use asset will be recognised on the Group balance sheet. This may be the case if, for example, EnQuest, as operator of the joint operation, is the sole signatory to the lease. If the underlying asset is used for the performance of the joint operation agreement, EnQuest will recharge the associated costs in line with the joint operating agreement.

As a lessor

When the Group acts as a lessor, it determines at lease inception whether each lease is a finance lease or an operating lease. Whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee, the contract is classified as a finance lease. All other leases are classified as operating leases.

When the Group is an intermediate lessor, it accounts for the head-lease and the sub-lease as two separate contracts. The sub-lease is classified as a finance or operating lease by reference to the right-of-use asset arising from the head-lease.

Rental income from operating leases is recognised on a straight-line basis over the term of the relevant lease. Initial direct costs incurred in negotiating and arranging an operating lease are added to the carrying amount of the leased asset and recognised on a straight-line basis over the lease term.

Amounts due from lessees under finance leases are recognised as receivables at the amount of the Group's net investment in the leases. Finance lease income is allocated to reporting periods so as to reflect a constant periodic rate of return on the Group's net investment outstanding in respect of the leases.

When a contract includes lease and non-lease components, the Group applies IFRS 15 to allocate the consideration under the contract to each component.

Right-of-use assets and lease liabilities

Set out below are the carrying amounts of the Group's right-of-use assets and lease liabilities and the movements during the period:

	Right-of-use assets $'000	Lease liabilities $'000
As at 31 December 2020	496,442	647,846
Additions in the period	17,815	17,815
Depreciation expense	(63,953)	-
Impairment reversal	15,669	-
Disposal	(2,580)	(3,121)
Interest expense	-	45,359
Payments	-	(136,651)
Foreign exchange movements	-	(467)
As at 31 December 2021	463,393	570,781
Additions in the period (see note 10)	28,394	28,130
Depreciation expense (see note 10)	(57,864)	-
Impairment charge (see note 10)	(2,991)	-
Disposal	(1,554)	(1,432)
Interest expense	-	39,172
Payments	-	(147,971)
Foreign exchange movements	-	(6,614)
As at 31 December 2022	429,378	482,066
Current		119,100
Non-current		362,966
		482,066

The Group leases assets including the Kraken FPSO, property and oil and gas vessels, with a weighted average lease term of four years. The maturity analysis of lease liabilities is disclosed in note 27.

Amounts recognised in profit or loss

	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Depreciation expense of right-of-use assets	57,864	63,953
Interest expense on lease liabilities	39,172	45,359
Rent expense - short-term leases	7,116	5,198
Rent expense - leases of low-value assets	50	5
Total amounts recognised in profit or loss	104,202	114,515

Amounts recognised in statement of cash flows

Year ended

31 December

2022

$'000

Year ended

31 December

2021
$'000

Total cash outflow for leases

147,971

136,651

Leases as lessor

The Group sub-leases part of Annan House, the Aberdeen office. The sub-lease is classified as an operating lease, as all the risks and rewards incidental to the ownership of the right-of-use asset are not all substantially transferred to the lessee. Rental income recognised by the Group during 2022 was $1.5 million (2021: $1.7 million).

The following table sets out a maturity analysis of lease payments, showing the undiscounted lease payments to be received after the reporting date:

	2022 $'000	2021 $'000
Less than one year	2,313	2,206
One to two years	2,542	2,206
Two to three years	1,905	2,206
Three to four years	822	2,206
Four to five years	824	2,206
More than five years	3,710	1,204
Total undiscounted lease payments	12,116	12,234

25. Commitments and contingencies

Capital commitments

At 31 December 2022, the Group had capital commitments amounting to $9.5 million (2021: $1.9 million).

Other commitments

In the normal course of business, the Group will obtain surety bonds, letters of credit and guarantees. At 31 December 2022, the Group held surety bonds totalling $227.6 million (2021: $240.8 million) to provide security for its decommissioning obligations. See note 23 for further details.

Contingencies

The Group becomes involved from time to time in various claims and lawsuits arising in the ordinary course of its business. Outside of those already provided for, the Group is not, nor has been during the past 12 months, involved in any governmental, legal or arbitration proceedings which, either individually or in the aggregate, have had, or are expected to have, a material adverse effect on the Group balance sheet or profitability. Nor, so far as the Group is aware, are any such proceedings pending or threatened.

26. Related party transactions

The Group financial statements include the financial statements of EnQuest PLC and its subsidiaries. A list of the Group's principal subsidiaries is contained in note 28 to these Group financial statements.

Balances and transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note.

All sales to and purchases from related parties are made at normal market prices and the pricing policies and terms of these transactions are approved by the Group's management. With the exception of the transactions disclosed below, there have been no transactions with related parties who are not members of the Group during the year ended 31 December 2022 (2021: none).

Compensation of key management personnel

The following table details remuneration of key management personnel of the Group. Key management personnel comprise Executive and Non-Executive Directors of the Company and the Executive Committee.

	2022 $'000	2021 $'000
Short-term employee benefits	6,195	6,890
Share-based payments	3,049	810
Post-employment pension benefits	164	215
Termination payments	228	-
	9,636	7,915

27. Risk management and financial instruments

Risk management objectives and policies

The Group's principal financial assets and liabilities comprise trade and other receivables, cash and cash equivalents, interest-bearing loans, borrowings and finance leases, derivative financial instruments and trade and other payables. The main purpose of the financial instruments is to manage short-term cash flow.

The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. Management reviews and agrees policies for managing each of these risks, which are summarised below. Also presented below is a sensitivity analysis to indicate sensitivity to changes in market variables on the Group's financial instruments and to show the impact on profit and shareholders' equity, where applicable. The sensitivity has been prepared for periods ended 31 December 2022 and 2021, using the amounts of debt and other financial assets and liabilities held at those reporting dates.

Commodity price risk - oil prices

The Group is exposed to the impact of changes in Brent oil prices on its revenues and profits generated from sales of crude oil.

The Group's policy is to have the ability to hedge oil prices up to a maximum of 75% of the next 12 months' production on a rolling annual basis, up to 60% in the following 12-month period and 50% in the subsequent 12-month period. On a rolling quarterly basis, under the RBL facility, the Group is required to hedge a minimum of 45% of volumes of net entitlement production expected to be produced in the next 12 months, and between 35% and 15% of volumes of net entitlement production expected for the following 12 months dependent on the proportion of the facility that is utilised. This requirement ceases at the end date of the facility.

Details of the commodity derivative contracts entered into during and open at the end of 2022 are disclosed in note 19. As of 31 December 2022, the Group held financial instruments (options and swaps) related to crude oil that covered 3.5 MMbbls of 2023 production. The instruments have an effective average floor price of around $56/bbl in 2023. The Group utilises multiple benchmarks when hedging production to achieve optimal results for the Group. No derivatives were designated in hedging relationships at 31 December 2022.

The following table summarises the impact on the Group's pre-tax profit of a reasonably possible change in the Brent oil price, on the fair value of derivative financial instruments, with all other variables held constant. The impact in equity is the same as the impact on profit before tax.

	Pre-tax profit
	+$10/bbl increase $'000	-$10/bbl decrease $'000
31 December 2022	(25,321)	19,922
31 December 2021	(91,755)	55,267

Foreign exchange risk

The Group is exposed to foreign exchange risk arising from movements in currency exchange rates. Such exposure arises from sales or purchases in currencies other than the Group's functional currency and the 7.00% retail bond which is denominated in Sterling. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of the non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged. Approximately 26% (2021: 18%) of the Group's sales and 85% (2021: 89%) of costs (including operating and capital expenditure and general and administration costs) are denominated in currencies other than the functional currency.

The Group also enters into foreign currency swap contracts from time to time to manage short-term exposures. The following tables summarise the Group's financial assets and liabilities exposure to foreign currency.

Year ended 31 December 2022

USD

$'000

GBP

$'000

MYR

$'000

Other

$'000

Total

$'000

Total financial assets

45,732

38,664

746

85,142

Total financial liabilities

502,307

13,202

151

515,660

Year ended 31 December 2021

USD

$'000

GBP

$'000

MYR

$'000

Other

$'000

Total

$'000

Total financial assets

103,253

34,255

3,967

141,475

Total financial liabilities

635,840

21,058

839

657,737

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 in 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:

	Pre-tax profit
	+$10% rate increase $'000	-$10% rate decrease $'000
31 December 2022	(96,010)	96,010
31 December 2021	(50,695)	50,695

Credit risk

Credit risk is managed on a Group basis. Credit risk in financial instruments arises from cash and cash equivalents and derivative financial instruments where the Group's exposure arises from default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments. For banks and financial institutions, only those rated with an A-/A3 credit rating or better are accepted. Cash balances can be invested in short-term bank deposits and AAA-rated liquidity funds, subject to Board-approved limits and with a view to minimising counterparty credit risks.

In addition, there are credit risks of commercial counterparties including exposures in respect of outstanding receivables. The Group trades only with recognised international oil and gas companies, commodity traders and shipping companies and at 31 December 2022 there were nil trade receivables past due but not impaired (2021: $0.2 million) and $0.1 million of joint venture receivables past due but not impaired (2021: nil). Subsequent to the year end, none of these outstanding balances have been collected (2021: $0.1 million). Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary. The impact of ECL is disclosed in note 16.

Ageing of past due but not impaired receivables	2022 $'000	2021 $'000
Less than 30 days	-	-
30-60 days	-	30
60-90 days	-	146
90-120 days	-	-
120+ days	123	-
	123	176

At 31 December 2022, the Group had two customer accounting for 79% of outstanding trade receivables (2021: one customer, 84%) and one joint venture partner accounting for 25% of outstanding joint venture receivables (2021: one joint venture partner, 20%).

Liquidity risk

The Group monitors its risk of a shortage of funds by reviewing its cash flow requirements on a regular basis relative to its existing bank facilities and the maturity profile of its borrowings. Specifically, the Group's policy is to ensure that sufficient liquidity or committed facilities exist within the Group to meet its operational funding requirements and to ensure the Group can service its debt and adhere to its financial covenants. At 31 December 2022, $47.3 million (2021: $32.0 million) was available for drawdown under the Group's facilities (see note 18).

The following tables detail the maturity profiles of the Group's non-derivative financial liabilities including projected interest thereon. The amounts in these tables are different from the balance sheet as the table is prepared on a contractual undiscounted cash flow basis and includes future interest payments.

The payment of contingent consideration is limited to cash flows generated from Magnus (see note 22). Therefore, no contingent consideration is payable if insufficient cash flows are generated over and above the requirements to operate the asset and there is no exposure to liquidity risk. By reference to the conditions existing at the reporting period end, the maturity analysis of the contingent consideration is disclosed below. All of the Group's liabilities, except for the RBL facility, are unsecured.

Year ended 31 December 2022	On demand $'000	Up to 1 year $'000	1 to 2 years $'000	2 to 5 years $'000	Over 5 years $'000	Total $'000
Loans and borrowings	-	163,223	175,400	152,000	-	490,623
Bonds(i)	-	194,991	49,919	615,449	-	860,359
Contingent considerations	-	126,910	85,267	327,642	400,480	940,299
Obligations under finance leases	-	151,621	127,592	256,139	37,693	573,045
Trade and other payables	-	426,643	-	-	-	426,643
	-	1,063,388	438,178	1,351,230	438,173	3,290,969

(i) Maturity analysis profile for the Group's bonds includes semi-annual coupon interest. The interest relating to the retail bond 7.00% is only payable in cash if the average dated Brent oil price is equal to or greater than $65/bbl for the six months preceding one month before the coupon payment date (see note 18)

Year ended 31 December 2021	On demand $'000	Up to 1 year $'000	1 to 2 years $'000	2 to 5 years $'000	Over 5 years $'000	Total $'000
Loans and borrowings	-	241,937	204,081	-	-	446,018
Bonds(i)	-	75,862	1,162,595	-	-	1,238,457
Contingent considerations	-	26,225	68,947	115,485	183,969	394,626
Obligations under finance leases	-	125,374	95,464	311,276	35,844	567,958
Trade and other payables	-	420,543	-	-	-	420,543
	-	889,941	1,531,087	426,761	219,813	3,067,602

(i) Maturity analysis profile for the Group's bonds includes semi-annual coupon interest. This interest is only payable in cash if the average dated Brent oil price is equal to or greater than $65/bbl for the six months preceding one month before the coupon payment date (see note 18)

The following tables detail the Group's expected maturity of payables for its derivative financial instruments. The amounts in these tables are different from the balance sheet as the table is prepared on a contractual undiscounted cash flow basis. When the amount receivable or payable is not fixed, the amount disclosed has been determined by reference to a projected forward curve at the reporting date.

Year ended 31 December 2022	On demand $'000	Less than 3 months $'000	3 to 12 months $'000	1 to 2 years $'000	Over 2 years $'000	Total $'000
Commodity derivative contracts	9,549	27,496	15,553	-	-	52,598
Other derivative contracts	880	4,429	-	-	-	5,309
	10,429	31,925	15,553	-	-	57,907

Year ended 31 December 2021

On demand

$'000

Less than

3 months

$'000

3 to 12 months

$'000

1 to 2 years

$'000

Over 2 years

$'000

Total

$'000

Commodity derivative contracts

4,450

17,288

24,035

15,746

61,519

4,450

17,288

24,035

15,746

61,519

Capital management

The capital structure of the Group consists of debt, which includes the borrowings disclosed in note 18, cash and cash equivalents and equity attributable to the equity holders of the parent company, comprising issued capital, reserves and retained earnings as in the Group statement of changes in equity.

The primary objective of the Group's capital management is to optimise the return on investment, by managing its capital structure to achieve capital efficiency whilst also maintaining flexibility. 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 the Board to hedge external risks, see Commodity price risk: oil prices and Foreign exchange risk. This is designed to reduce the risk of adverse movements in exchange rates and market prices eroding the return on the Group's projects and operations.

The Board regularly reassesses the existing dividend policy to ensure that shareholder value is maximised. Any future payment of dividends is expected to depend on the earnings and financial condition of the Company and such other factors as the Board considers appropriate.

The Group monitors capital using the gearing ratio and return on shareholders' equity as follows. Further information relating to the movement year-on-year is provided within the relevant notes and within the Financial review (pages 11 to 16).

	2022 $'000	2021 $'000
Loans, borrowings and bond(i) (A) (see note 18)	1,018,712	1,508,604
Cash and short-term deposits (see note 14)	(301,611)	(286,661)
EnQuest net debt (B)	717,101	1,221,943
Equity attributable to EnQuest PLC shareholders (C)	484,241	543,766
Profit/(loss) for the year attributable to EnQuest PLC shareholders (D)	(41,234)	376,988
Profit/(loss) for the year attributable to EnQuest PLC shareholders excluding remeasurements and exceptionals (E)	212,346	220,284
Adjusted EBITDA (F)	979,084	742,868
Gross gearing ratio (A/C)	2.1	2.8
Net gearing ratio (B/C)	1.5	2.2
EnQuest net debt/adjusted EBITDA (B/F)	0.7	1.6
Shareholders' return on investment (D/C)	N/A	74%
Shareholders' return on investment excluding exceptionals (E/C)	44%	41%

(i) Principal amounts drawn, excludes netting off of fees (see note 18)

28. Subsidiaries

At 31 December 2022, EnQuest PLC had investments in the following subsidiaries:

Name of company	Principal activity	Country of incorporation	Proportion of nominal value of issued shares controlled by the Group
EnQuest Britain Limited	Intermediate holding company and provision of Group manpower and contracting/procurement services	England	100%
EnQuest Heather Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Thistle Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
Stratic UK (Holdings) Limited(i)	Intermediate holding company	England	100%
Grove Energy Limited1	Intermediate holding company	Canada	100%
EnQuest ENS Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest UKCS Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Heather Leasing Limited(i)	Leasing	England	100%
EQ Petroleum Sabah Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Dons Leasing Limited(i)	Leasing	England	100%
EnQuest Energy Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Production Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Global Limited	Intermediate holding company	England	100%
EnQuest NWO Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EQ Petroleum Production Malaysia Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
NSIP (GKA) Limited2	Construction, ownership and operation of an oil pipeline	Scotland	100%
EnQuest Global Services Limited(i)3	Provision of Group manpower and contracting/procurement services for the international business	Jersey	100%
EnQuest Marketing and Trading Limited	Marketing and trading of crude oil	England	100%
NorthWestOctober Limited(i)	Dormant	England	100%
EnQuest UK Limited(i)	Dormant	England	100%
EnQuest Petroleum Developments Malaysia SDN. BHD(i)4	Exploration, extraction and production of hydrocarbons	Malaysia	100%
EnQuest NNS Holdings Limited(i)	Intermediate holding company	England	100%
EnQuest NNS Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Advance Holdings Limited(i)	Intermediate holding company	England	100%
EnQuest Advance Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Forward Holdings Limited(i)	Intermediate holding company	England	100%
EnQuest Forward Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Progress Limited(i)	Exploration, extraction and production of hydrocarbons	England	100%
North Sea (Golden Eagle) Resources Ltd	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest CCS Limited(i) Veri Energy Holdings Limited Veri Energy Limited(i)	Non-trading Intermediate holding company Dormant	England England England	100% 100% 100%

(i) Held by subsidiary undertaking

The Group has two branches outside the UK (all held by subsidiary undertakings): EnQuest Global Services Limited (Dubai) and EnQuest Petroleum Production Malaysia Limited (Malaysia).

Registered office addresses:

1 Suite 2200, 1055 West Hastings Street, Vancouver, British Columbia, V6E 2E9

2 Annan House, Palmerston Road, Aberdeen, Scotland, AB11 5QP, United Kingdom

3 Ground Floor, Colomberie House, St Helier, JE4 0RX, Jersey

4 c/o TMF, 10th Floor, Menara Hap Seng, No. 1 & 3, Jalan P. Ramlee 50250 Kuala Lumpur, Malaysia

29. Cash flow information

Cash generated from operations

	Notes	Year ended 31 December 2022 $'000	Year ended 31 December 2021 $'000
Profit/(loss) before tax		203,214	352,441
Depreciation	5(c)	6,222	7,492
Depletion	5(b)	327,026	305,578
Net impairment charge/(reversal) to oil and gas assets	4	81,049	(39,715)
Write down of inventory		762	151
Change in fair value of investments		-	1
Share-based payment charge	5(f)	4,719	6,351
Change in Magnus related contingent consideration	22	268,910	(81,684)
Change in provisions	23	(25,001)	16,900
Other non-cash income	5(d)	(6,636)	(22,568)
Other expense on final settlement relating to the Magnus acquisition	5(e)	-	3,832
Change in Golden Eagle related contingent consideration	22	3,162	507
Option premiums	19	1,331	1,030
Unrealised (gain)/loss on commodity financial instruments	5(a)	(14,475)	54,451
Unrealised (gain)/loss on other financial instruments	5(b)	4,900	(472)
Unrealised exchange loss/(gain)		(13,588)	(425)
Net finance expense		154,492	152,306
Operating profit before working capital changes		996,087	756,176
Decrease/(increase) in trade and other receivables		12,714	(171,946)
(Increase)/decrease in inventories		(5,388)	(13,496)
Increase/(decrease) in trade and other payables		22,736	186,194
Cash generated from operations		1,026,149	756,928

Changes in liabilities arising from financing activities

	Loans and borrowings $'000	Bonds $'000	Lease liabilities $'000	Total $'000
At 1 January 2021	(452,774)	(1,079,692)	(647,846)	(2,180,312)
Cash movements:
Repayments of loans and borrowings	184,276	-	-	184,276
Drawdowns of loans and borrowings	(125,000)	-	-	(125,000)
Repayment of lease liabilities	-	-	136,651	136,651
Cash interest paid in year	19,428	38,154	-	57,582
Non-cash movements:
Additions	2,082	-	(17,815)	(15,733)
Interest/finance charge payable	(20,206)	(69,085)	(45,359)	(134,650)
Fee amortisation	(9,857)	(1,173)	-	(11,030)
Disposal	-	-	3,121	3,121
Foreign exchange and other non-cash movements	(14)	1,876	467	2,329
At 31 December 2021	(402,065)	(1,109,920)	(570,781)	(2,082,766)
Cash movements:
Repayments of loans and borrowings	415,000	827,131	-	1,242,131
Drawdowns of loans and borrowings	(409,180)	(376,163)	-	(785,343)
Repayment of lease liabilities	-	-	147,971	147,971
Cash interest paid in year	14,771	80,189	-	94,960
Non-cash movements:
Additions	4,038	14,323	(28,130)	(9,769)
Interest/finance charge payable	(14,490)	(62,262)	(39,172)	(115,924)
Fee amortisation	(22,679)	(2,652)	-	(25,331)
Disposal	-	-	1,432	1,432
Foreign exchange and other non-cash movements	1,077	32,071	6,614	39,762
At 31 December 2022	(413,528)	(597,283)	(482,066)	(1,492,877)

Reconciliation of carrying value

	Loans and borrowings (see note 18) $'000	Bonds (see note 18) $'000	Lease liabilities (see note 24) $'000	Total $'000
Principal	(424,864)	(1,083,740)	(570,781)	(2,079,385)
Unamortised fees	23,250	2,144	-	25,394
Accrued interest (note 17)	(451)	(28,324)	-	(28,775)
At 31 December 2021	(402,065)	(1,109,920)	(570,781)	(2,082,766)
Principal	(417,967)	(600,745)	(482,066)	(1,500,778)
Unamortised fees	4,609	13,815	-	18,424
Accrued interest (note 17)	(170)	(10,353)	-	(10,523)
At 31 December 2022	(413,528)	(597,283)	(482,066)	(1,492,877)

Glossary - Non-GAAP measures

The Group uses Alternative Performance Measures ('APMs') when assessing and discussing the Group's financial performance, balance sheet and cash flows that are not defined or specified under IFRS. The Group uses these APMs, which are not considered to be a substitute for, or superior to, IFRS measures, to provide stakeholders with additional useful information by adjusting for exceptional items and certain remeasurements which impact upon IFRS measures or, by defining new measures, to aid the understanding of the Group's financial performance, balance sheet and cash flows.

The use of the Business performance APM is explained in note 2 of the Group's consolidated financial statements on page 31.

Business performance net profit attributable to EnQuest PLC shareholders	2022 $'000	2021 $'000
Reported net profit/(loss) (A)	(41,234)	376,988
Adjustments - remeasurements and exceptional items (note 4):
Unrealised gains/(losses) on derivative contracts (note 19)	9,575	(53,979)
Net impairment (charge)/reversal to oil and gas assets (note 10, note 11 and note 12)	(81,049)	39,715
Finance costs on Magnus contingent consideration (note 6)	(36,410)	(58,395)
Change in Magnus contingent consideration (2022: notes 5(d) and 5(e); 2021: note 5(d))	(232,500)	140,079
Movement in other provisions	-	(7,673)
Other exceptional income (note 5(d))	6,636	22,568
Other exceptional expenses (note 5(e))	-	(3,832)
Other exceptional finance income (note 6)	2,148	-
Pre-tax remeasurements and exceptional items (B)	(331,600)	78,483
Tax on remeasurements and exceptional items (C)	78,020	78,221
Post-tax remeasurements and exceptional items (D = B + C)	(253,580)	156,704
Business performance net profit attributable to EnQuest PLC shareholders (A - D)	212,346	220,284

Adjusted EBITDA is a measure of profitability. It provides a metric to show earnings before the influence of accounting (i.e. depletion and depreciation) and financial deductions (i.e. borrowing interest). For the Group, this is a useful metric as a measure to evaluate the Group's underlying operating performance and is a component of a covenant measure under the Group's RBL facility. It is commonly used by stakeholders as a comparable metric of core profitability and can be used as an indicator of cash flows available to pay down debt. Due to the adjustment made to reach adjusted EBITDA, the Group notes the metric should not be used in isolation. The nearest equivalent measure on an IFRS basis is profit or loss from operations before tax and finance income/(costs).

Adjusted EBITDA	2022 $'000	2021 $'000
Reported profit/(loss) from operations before tax and finance income/(costs)	411,887	580,059
Adjustments:
Remeasurements and exceptional items (note 4)	297,338	(136,878)
Depletion and depreciation (note 5(b) and note 5(c))	333,248	313,070
Inventory revaluation	763	151
Change in provision (note 5(d) and note 5€)	(42,823)	(13,143)
Net foreign exchange (gain)/loss (note 5(d))	(21,329)	(391)
Adjusted EBIT€(E)	979,084	742,868

Total cash and available facilities is a measure of the Group's liquidity at the end of the reporting period. The Group believes this is a useful metric as it is an important reference point for the Group's going concern and viability assessments, see pages 15 to 16.

Total cash and available facilities	2022 $'000	2021 $'000
Available cash	293,866	276,970
Restricted cash	7,745	9,691
Total cash and cash equivalents (F) (note 14)	301,611	286,661

Available credit facilities	500,000	500,000
Credit facility - drawn down	(400,000)	(415,000)
Letter of credit (note 18)	(52,700)	(53,000)
Available undrawn facility (G)	47,300	32,000
Total cash and available facilities (F + G)	348,911	318,661

Net debt is a liquidity measure that shows how much debt a company has on its balance sheet compared to its cash and cash equivalents. With de-leveraging a strategic priority, the Group believes this is a useful metric to demonstrate progress in this regard. It is also an important reference point for the Group's going concern and viability assessments, see pages 15 to 16. The Group's definition of net debt, referred to as EnQuest net debt, excludes the Group's finance lease liabilities as the Group's focus is the management of cash borrowings and a lease is viewed as deferred capital investment.

EnQuest net debt	2022 $'000	2021 $'000
Borrowings (note 18):
RBL facility	395,391	391,750
SVT working capital facility	12,275	9,864
Vendor loan facility	5,692	-
Borrowings (H)	413,358	401,614
Bonds (note 18):
High yield bond	291,185	825,441
Retail bonds	295,745	256,155
Bonds (I)	586,930	1,081,596
Non-cash accounting adjustments (note 18):
Unamortised fees on loans and borrowings	4,609	23,250
Unamortised fees on bonds	13,815	2,144
Non-cash accounting adjustments (J)	18,424	25,394
Debt (H + I + J) (K)	1,018,712	1,508,604
Less: Cash and cash equivalents (note 14) (E)	301,611	286,661
EnQuest net debt/(cash) (K - F) (L)	717,101	1,221,943

The EnQuest net debt/adjusted EBITDA metric is a ratio that provides management and users of the Group's consolidated financial statements with an indication of how many years it would take to service the Group's debt. This is a helpful metric to monitor the Group's progress against its strategic objective of de-leveraging .

EnQuest net debt/adjusted EBITDA	2022 $'000	2021 $'000
EnQuest net debt (L)	717,101	1,221,943
Adjusted EBITDA (E)	979,084	742,868
EnQuest net debt/adjusted EBITDA (L/E)	0.7	1.6

Cash capex monitors investing activities on a cash basis, while cash decommissioning expense monitors the Group's cash spend on decommissioning activities. The Group provides guidance to the financial markets for both these metrics given the focus on the Group's liquidity position and ability to reduce its debt.

Cash capex and Cash capital and decommissioning expense	2022 $'000	2021 $'000
Reported net cash flows (used in)/from investing activities	(161,247)	(321,230)
Adjustments:
Purchase of other intangible assets	1,199	10,052
Repayment of Magnus contingent consideration - Profit share	45,975	968
Acquisition costs	-	258,627
Interest received	(1,763)	(256)
Cash capex	(115,836)	(51,839)
Decommissioning spend	(58,964)	(65,791)
Cash capital and decommissioning expense	(174,800)	(117,630)

Free cash flow ('FCF') represents the cash a company generates, after accounting for cash outflows to support operations, to maintain its capital assets . Currently this metric is useful to management and users to assess the Group's ability to reduce its debt.

The Group's definition of free cash flow is net cash flow adjusted for net repayment/proceeds of loans and borrowings, net proceeds of share issues and cost of acquisitions.

In 2021, the Group made an accelerated repayment of the Magnus Vendor loan of $58.7 million. As the repayment was made out of Group cash flows rather than as part of the Magnus-related waterfall mechanism, the Group has adjusted for this accelerated repayment for the purpose of calculating FCF.

Free cash flow	2022 $'000	2021 $'000
Net cash flows from/(used in) operating activities	931,553	674,138
Net cash flows from/(used in) investing activities	(161,247)	(321,230)
Net cash flows from/(used in) financing activities	(731,163)	(285,474)
Adjustments:
Net proceeds of loans and borrowings	(65,473)	(125,000)
Net repayment of loans and borrowings	545,278	184,276
Acquisitions	-	258,627
Repayment of Magnus contingent consideration - Vendor loan⁽ⁱ⁾	-	58,668
Net proceeds from share issue	-	(47,782)
Shares purchased by Employee Benefit Trust	-	576
Free cash flow	518,948	396,799

(i) Related to the accelerated vendor loan repayment

Revenue sales	2022 $'000	2021 $'000
Revenue from crude oil sales (note 5(a)) (M)	1,517,666	1,139,171
Revenue from gas and condensate sales (note 5(a)) (N)	514,206	244,073
Realised (losses)/gains on oil derivative contracts (note 5(a)) (P)	(203,741)	(67,679)

Barrels equivalent sales	2022 kboe	2021 kboe
Sales of crude oil (Q)	14,786	15,609
Sales of gas and condensate(i)	3,366	2,829
Total sales (R)	18,152	18,438

(i) Includes volumes related to onward sale of third-party gas purchases not required for injection activities at Magnus

Average realised price is a measure of the revenue earned per barrel sold. The Group believes this is a useful metric for comparing performance to the market and to give the user, both internally and externally, the ability to understand the drivers impacting the Group's revenue.

Average realised prices	2022 $/Boe	2021 $/Boe
Average realised oil price, excluding hedging (M/Q)	102.6	73.0
Average realised oil price, including hedging ((M + P)/Q)	88.9	68.6
Average realised blended price, excluding hedging ((M + N)/R)	111.9	75.0
Average realised blended price, including hedging ((M + N + P)/R)	100.7	71.4

Operating costs ('opex') is a measure of the Group's c ost management performance. Opex is a key measure to monitor the Group's alignment to its strategic pillars of financial discipline and value enhancement and is required in order to calculate opex per barrel (see below).

Operating costs	2022 $'000	2021 $'000
Reported cost of sales (note 5(b))	1,200,706	907,634
Adjustments:
Remeasurements and exceptional items (note 5(b))	(4,900)	(7,201)
Depletion of oil and gas assets (note 5(b))	(327,027)	(305,578)
Charge/(credit) relating to the Group's lifting position and inventory (note 5(b))	15,568	(62,307)
Other cost of operations (note 5(b))	(487,831)	(211,575)
Operating costs	396,516	320,973
Less realised (gain)/loss on derivative contracts (S) (note 5(b))	(5,418)	10,693
Operating costs directly attributable to production	391,098	331,666
Comprising of:
Production costs (T) (note 5(b))	347,832	292,252
Tariff and transportation expenses (U) (note 5(b))	43,266	39,414
Operating costs directly attributable to production	391,098	331,666

Barrels equivalent produced

2022

kboe

2021

kboe

Total produced (working interest) (V)

17,250

16,211

Unit opex is the operating expenditure per barrel of oil equivalent produced. This metric is useful as it is an industry standard metric allowing comparability between oil and gas companies. Unit opex including hedging includes the effect of realised gains and losses on derivatives related to foreign currency and emissions allowances. This is a useful measure for investors because it demonstrates how the Group manages its risk to market price movements.

Unit opex	2022 $/Boe	2021 $/Boe
Production costs (T/V)	20.2	18.1
Tariff and transportation expenses (U/V)	2.5	2.4
Total unit opex ((T + U)/V)	22.7	20.5
Realised loss/(gain) on derivative contracts (S/V)	0.3	(0.7)
Total unit opex including hedging ((S + T+ U)/V)	23.0	19.8

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