EnQuest PLC Results for the year ended 31 December 2023

RNS Number : 6690I

EnQuest PLC

28 March 2024

EnQuest PLC, 28 March 2024

Results for the year ended 31 December 2023 and 2024 outlook

De-levered and positioned to deliver transformational growth

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 year ended 31 December 2022 and the Balance Sheet as at 31 December 2022. Alternative performance measures are reconciled within the 'Glossary - Non-GAAP measures' at the end of the Financial Statements.

EnQuest Chief Executive, Amjad Bseisu, said:

"EnQuest achieved its 2023 targets, delivering strong operational performance across the operated portfolio and continuing to de-lever its balance sheet, with year-end EnQuest net debt reduced to $481 million. Against the backdrop of a challenging UK fiscal environment, EnQuest has reduced net debt by c.$1.5 billion since its peak and with significant tax assets remaining, the business has a strong base, and successful track record of executing quick payback, life-extending acquisitions, from which to pursue value-accretion and production growth through M&A.

"Our top quartile operating capability, demonstrated through high production uptimes across our operated asset portfolio, underpinned 2023 production of 43.8 Kboed, which was in line with the mid-point of guidance. This operational excellence extends to our decommissioning activities, with 2023 seeing the Group complete the plug and abandonment ('P&A') of 25 wells, delivering top quartile well P&A performance across its Heather and Thistle projects and executing another record-breaking year of northern North Sea multi-asset well abandonments at sector-leading cost.

"We also realised value within the existing portfolio by selling a 15.0% share of both the Bressay licence and the EnQuest Producer FPSO to RockRose Energy; a transaction which represents an important step in moving the Bressay project forward.

"As we further enhance our position as a key player in the energy transition, we continue to progress our new energy and decarbonisation ambitions at the Sullom Voe Terminal under the management of our newly established subsidiary, Veri Energy. The award of four carbon storage licences during 2023 represented a key milestone for our future ambitions. Work is underway to right-size the terminal site and transform its carbon footprint, with delivery of the new stabilisation facility and power generation projects expected to reduce future CO₂ emissions at SVT by c.90%. We have already reduced our total UK emissions by more than 40% from the 2018 benchmark, significantly ahead of the UK's North Sea Transition Deal targets, while our credible net zero transition plan was a key factor in EnQuest securing a B rating in the 2023 CDP Climate Change Survey.

"We have set the foundations for a pivot to growth during 2024 and continue to perform well against our full year targets, with production to 29 February 2024 averaging around 44,500 Boepd. The Group also fully paid down its RBL facility post year-end and has further reduced net debt to $409.6 million at the end of February 2024.

"Reflecting the strength of our core business, confidence in the opportunities ahead and the Group's commitment to delivering shareholder returns during 2024, we have committed to deploy $15.0 million of capital in a share buyback programme during 2024."

2023 performance

§ Statutory revenue and other income totalled $1,487.4 million (2022: $1,853.6 million) and adjusted EBITDA totalled $824.7 million (2022: $979.1 million).

§ Against a backdrop of continued geopolitical tension, inflation and Sterling volatility, Brent prices averaged $82.5/bbl (18.2% below 2022: $100.8/bbl) and day ahead gas prices decreased to 98.9p/Therm (51.4% below 2022: 203.5p/Therm).

§ Group production (delivered at the mid-point of guidance) averaged 43,812 Boepd (2022: 47,259 Boepd), with high levels of asset uptime across the portfolio and efficient execution of maintenance activities partially offsetting natural field declines.

§ Reflecting the above drivers and cash tax timing, net operating cash flow totalled $754.2 million, 19.0% below 2022 ($931.6 million).

§ Operating expenditure of $347.2 million was 12.4% below 2022 ($396.5 million). Unit opex declined to $21.9/boe (2022: $22.7/boe).

§ Capital investment of $152.2 million (2022: $115.8 million) was focused on low cost, quick payback projects that enhanced production and lowered emissions. Decommissioning expenditure totalled $58.9 million (2022: $59.0 million) and focused on well P&A.

§ Free cash flow generation¹ remained strong, totalling $300.0 million (2022: $518.9 million).

§ Statutory reported loss after tax $30.8 million (2022: $41.2 million loss), reflecting the impact of the UK Energy Profits Levy.

§ Group liquidity (cash and available facilities) rose to $498.8 million (31 December 2022: $348.9 million). EnQuest net debt totalled $480.9 million at 31 December 2023, a 32.9% reduction versus 2022 ($717.1 million).

§ Having delivered on the Group's strategic aims to deliver and de-lever, EnQuest is pleased to announce its first shareholder distribution, a $15.0 million buyback that will be completed in 2024.

¹ Net change in cash and cash equivalents less acquisition costs and net repayments/proceeds from loans and borrowing and share issues

2024 performance and guidance

§ Net Group production expected to average between 41,000 and 45,000 Boepd (c.44,500 Boepd YTD to end-February).

§ Capital investment expected to total c.$200 million; Operating expenditure expected to total c.$415 million; and Decommissioning expenditure expected to total c.$70 million.

§ Investment is scaled to maintain production, maximise cash flow, drive capital efficiency and reduce future emissions and costs.

§ At 29 February 2024, EnQuest net debt totalled $409.6 million and the Group fully repaid the outstanding $140.0 million of its drawn reserve based lending facility ('RBL').

Outlook - 2025 and beyond

§ Capital-efficient investment programme; targeting organic production growth in 2025.

§ Kraken FPSO lease rate reduces by c.70% from 1 April 2025 and major projects at SVT are expected to crystallise significant emissions and operating cost reductions in 2026 and beyond.

Production and financial information

Macro conditions	2023	2022	Change
Brent oil price⁴ ($/bbl)	82.5	100.8	-18.2%
Natural gas price⁴ (GBp/Therm)	98.9	203.5	-51.4%

Business performance measures	2023	2022	Change
Production (Boepd)	43,812	47,259	-7.3%
Revenue and other operating income ($m)¹	1,459.0	1,839.1	-20.7%
Realised oil price ($/bbl)^1,2	81.4	88.9	-8.4%
Average unit operating costs ($/Boe)²	21.9	22.7	-3.5%
Adjusted EBITDA ($m)²	824.7	979.1	-15.8%
Cash expenditures ($m)	211.1	174.8	20.8%
Capital²	152.2	115.8	31.4%
Decommissioning	58.9	59.0	-0.0%
Free cash flow ($m)²	300.0	518.9	-42.2%

	End 2023	End 2022
EnQuest net (debt)/cash ($m)²	(480.9)	(717.1)	-32.9%

Statutory measures	2023	2022	Change %
Reported revenue and other operating income ($m)³	1,487.4	1,853.6	-19.8%
Reported gross profit ($m)	540.7	652.9	-17.2%
Reported profit/(loss) after tax ($m)	(30.8)	(41.2)	25.2%
Reported basic earnings/(loss) per share (cents)	(1.6)	(2.2)	27.3%
Net cash flow from operating activities ($m)	754.2	931.6	-19.0%
Net increase/(decrease) in cash and cash equivalents ($m)	12.9	39.1	-67.0%

Notes:

¹ Including realised losses of $11.3 million (2022: realised losses of $203.7 million) associated with EnQuest's oil price hedges

² See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP Measures' starting on page 65.

³ Including net realised and unrealised gains of $17.2 million (2022: net realised and unrealised losses of $189.3 million) associated with EnQuest's oil price hedges

⁴ Source is Reuters Factset

2023 performance summary

Strong production performance, a lower but relatively stable commodity price environment and the Group's commitment to disciplined, low cost, quick payback investment underpinned $300.0 million of free cash flow generation during 2023 (2022: $518.9 million). This enabled the Group to end the year with liquidity of c.$0.5 billion and reduce EnQuest net debt to $480.9 million (2022: $717.1 million). At 31 December 2023, the EnQuest net debt to adjusted EBITDA ratio was down to 0.6x, (31 December 2022: 0.7x), which shows continued progress towards the target of 0.5x.

Production of 43,812 Boepd (2022: 47,259 Boepd) reflected improved performance at Magnus and close to 100% production efficiency at Kraken following transformer upgrades, with top quartile production uptime across the operated portfolio helping to partially offset natural field declines. The Group demonstrated its differentiated operating capability by minimising the impact of the anomalous failure of the HSP transformers by reinstating Kraken production efficiently and in a short-time frame.

Adjusted EBITDA, net cash flow from operating activities and free cash flow were $824.7 million (2022: $979.1 million), $754.2 million (2022: $931.6 million) and $300.0 million (2022: $518.9 million), respectively, with the decreases from 2022 reflecting lower production and market prices. Capital expenditure of $152.2 million (2022: $115.8 million) primarily reflected the Magnus, Golden Eagle and Malaysia well campaigns and Sullom Voe Terminal projects, while cash decommissioning expenditure of $58.9 million (2022: $59.0 million) was focused on well plug and abandonment ('P&A') activities at Heather and Thistle, with a record 25 wells being decommissioned during the year.

Following the establishment of the New Energy business in 2021 and having progressed three significant new energy and decarbonisation opportunities at Sullom Voe Terminal, the Group launched Veri Energy ('Veri'), a wholly owned subsidiary of EnQuest. Veri represents the logical next step in the strategic evolution of EnQuest's new energy and decarbonisation ambitions, enabling the project team to move forward with a focused management structure and the potential to leverage financial and strategic partnerships.

In December, EnQuest announced the sale of a 15.0% equity share in the Bressay licence and the EnQuest Producer FPSO for a total consideration of £46.0 million (c. $57.0 million). Subsequently the Group received $85.6 million for a 15.0% farm-down of capital items identified for potential use on the Bressay development. Through these transactions the Group has realised near-term value, expecting to yield c.$58.0 million post-tax cash flow in 2024, and delivered an important step in moving the Bressay project forward.

Liquidity and net debt

At 31 December 2023, EnQuest net debt was $480.9 million, down $236.2 million from $717.1 million at 31 December 2022. During the year, EnQuest repaid the Group's £111.3 million Sterling retail bond at maturity and put in place a term loan facility of up to $150.0 million. Following these steps, all the Group's debt maturities are now aligned in 2027.

At 31 December 2023, cash drawings under the reserve based lending ('RBL') facility were $140.0 million against an original commitment of $500.0 million, while total cash and available facilities were $498.8 million (2022: $348.9 million) (including restricted funds and ring-fenced funds held in joint venture operational accounts totalling $172.7 million (2022: $174.3 million)).

EnQuest net debt as at 29 February 2024 was further reduced to $409.6 million, with cash and available facilities of $479.7 million. The Group also fully repaid the $140.0 million outstanding balance on the RBL facility during February 2024, reducing cash drawn to zero.

EnQuest remains focused on its strong balance sheet and its ongoing deleveraging strategy. From a position of balance sheet strength, EnQuest is pleased to announce the first shareholder distribution since its inception, a $15.0 million buyback that will be completed in 2024.

Reserves and resources

Net 2P reserves at the end of 2024 were c.175 MMboe (2022: c.190 MMboe). During the year, the Group produced c.16 MMboe (2022: c.17 MMboe). This reduction was partially offset by transfers from 2C resources at Magnus, net of other technical revisions. Net 2C resources were c.389 MMboe (2022: c.393 MMboe), with the decrease a result of progression to 2P reserves at Magnus, as noted above.

Environmental, Social and Governance

The health, safety and wellbeing of our employees remains our top priority. In 2023, EnQuest achieved Lost Time Incident ('LTI') frequency¹ rate of 0.52 (2022: 0.57). Whilst this was an improvement versus 2022, the Group will not be complacent as it strives to deliver SAFE results with no harm to our people.

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)

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. Since 2018, UK Scope 1 and 2 emissions have reduced by c.41%, which is significantly ahead of the UK Government's North Sea Transition Deal target of achieving a 10% reduction in Scope 1 and Scope 2 CO₂ equivalent emissions by 2025 and close to the 50% reduction targeted by 2030.

In recognition of progress to date in terms of emissions reduction and the Group's credible forward plans to deliver decarbonisation and new energy projects on the journey towards net zero by 2040, EnQuest is proud to have secured a B rating from the prestigious CDP Climate Change Survey.

EnQuest's 2024 strategic focus is to deliver a step-change in operational growth, diversification and carbon reduction, around which the Group has repositioned both its Board and Senior Management.

In the year, Salman Malik (previously Chief Financial Officer ('CFO') and Managing Director, Infrastructure and New Energy) has assumed the role of Chief Executive Officer of Veri Energy. One of the outcomes of his appointment as Veri CEO is that he will step down as a Director of EnQuest at the 2024 Annual General Meeting ('AGM'). In a refresh of the leadership team, Jonathan Copus was appointed EnQuest CFO and will be proposed for election to the Board at the AGM, while Steve Bowyer has joined EnQuest as North Sea General Manager.

Also, during 2023, our three longest serving Non-Executive Directors, Carl Hughes, Howard Paver, and John Winterman, stepped down from the Board at the 2023 Annual General Meeting ('AGM').

Subsequently, the Governance and Nomination Committee carried out a comprehensive search for independent Non-Executive Directors to join the Board, resulting in the appointment of Michael Borrell and Karina Litvack. Unfortunately, in December, Karina had to step down from the Board due to an unexpected conflict arising through the EU Unbundling Directive, which prohibits any director of a European power transmission company from also serving on the board of an upstream operator. As such, and as announced separately this morning, we intend to appoint Rosalind Kainyah to the Board at the Company's 2024 AGM.

Separately, both Liv Monica Stubholt and Rani Koya have advised that they will be stepping down at the Company's 2024 AGM. Liv Monica has served on the Board for a full three-year term and has opted to focus on her Norwegian portfolio, and Rani has advised of a need to focus on other work priorities.

At the end of 2023, the Group's Board membership was in line with the Women Leaders Review target of 40% female representation and work continues throughout the organisation to deliver on our diversity and inclusion targets. The Board currently has 43% female representation and remains ahead of the Parker Review target with respect to minority ethnic representation, with four minority ethnic Board members.

2024 performance and guidance

Group net production averaged around 44,500 Boepd to the end of February. For the full year, the Group's net production is expected to be between 41,000 and 45,000 Boepd, reflecting the drilling campaigns at Magnus, PM8/Seligi and Golden Eagle. Planned maintenance activities include two ten-day periods of single train operations at Kraken, with 21-day and ten-day shutdowns at each of Magnus and GKA, respectively.

Operating expenditures are expected to be approximately $415.0 million, with the increase from 2023 largely due to phasing of activities at Magnus and SVT and inflationary pressures.

Cash capital expenditure is expected to be around $200.0 million. The Group plans to execute a two-well drilling campaign at Magnus in the second half of the year, following the five-yearly rig recertification, and expects to complete the ongoing drilling campaign at Golden Eagle, where two further HDJU wells are planned. EnQuest's Midstream team is progressing two major right-sizing projects at SVT, which together are expected to reduce terminal emissions by c.90%.

Decommissioning expenditure is expected to total approximately $70.0 million, primarily reflecting the final full year of well P&A decommissioning programmes at the Heather/Broom and Thistle/Deveron fields and preparations for removal of the topsides production facilities. This work will be completed by EnQuest's dedicated in-house team which, per North Sea Transition Authority review data, has delivered a probabilistic average cost per well for P&A of c.£2.5 million, versus an industry benchmark of c.£4.3 million.

From 1 April 2024, EnQuest has hedged c.5.0 MMbbls of oil, with 4.1 MMbbls hedged through the use of put options with an average floor price of c.$60/bbl and 0.9 MMbbls through swaps at an average price of c.$86/bbl. The Group has hedged a total of c.1.6 MMbbls for 2025 using put options at an average floor price of c. $60/bbl.

Outlook - 2025 and beyond

The Group's 2024 capital-efficient investment programme targets organic production growth in 2025. From 1 April 2025, the Kraken FPSO lease rate reduces by c. 70% and major projects at SVT are expected to crystallise significant operating cost and emission reductions in 2026 and beyond.

Summary financial review of 2023

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

Overview

Strong free cash flow generation in the period of $300.0 million (2022: $518.9 million) drove a reduction in EnQuest net debt of 32.9%, to $480.9 million (31 Dec 2022: $717.1 million). At 31 December 2023, the Group's leverage ratio was 0.6x, close to its target of 0.5x, while cash and available facilities had increased to $498.8 million (2022: $348.9 million) with all debt now maturing in 2027.

During December, EnQuest announced the sale of a 15.0% equity share in the Bressay licence and the EnQuest Producer FPSO for a total consideration of £46.0 million (c. $57.0 million). Subsequently, the Group received $85.6 million for a 15.0% farm-down of capital items identified as suitable for use on the Bressay development. Through these transactions the Group has realised near-term value, expecting to yield c. $58.0 million post-tax cash flow in 2024, and delivered an important step in moving the project forward.

The Group's improved balance sheet, liquidity position and significantly advantaged tax position means EnQuest is well placed to pursue growth opportunities and the Group's Board has sanctioned the Company's first programme of shareholder returns - committing to a $15.0 million buy back that will be completed during 2024.

Income statement

Revenue

Brent prices in the period averaged $82.5/bbl (18.2% below 2022: $100.8/bbl) and the average day ahead gas price decreased to 98.9p/Therm (51.4% below 2022: 203.5p/Therm). Pre-hedging, the average oil price realised by EnQuest was $82.2/bbl (19.9% below 2022: $102.6/bbl). Post-hedging, realised oil prices averaged $81.4/bbl, narrowing the discount year-on-year to 8.4% ($88.9/bbl).

Reflecting these drivers, reported revenue totalled $1,487.4 million, a 19.8 % decline on 2022 ($1,853.6 million). Within this figure, oil sales accounted for $1,127.4 million, 25.7% below 2022 ($1,517.7 million).

Realised losses on commodity hedges totalled $11.3 million (2022: losses of $203.7 million). Unrealised gains on these contracts (mark-to-market movements) totalled $28.5 million (2022: unrealised gains of $14.5 million).

Revenue from the sale of condensate and gas, totalling $339.0 million (2022: $514.2 million), primarily relates to the onward sale of third-party gas that was not required for injection activities at Magnus. The contribution from these volumes is offset by related costs in cost of sales. Tariffs and other income generated a further $3.8 million (2022: $11.0 million), including income from the transportation of Seligi Associated gas.

Cost of sales

The Group demonstrated effective cost control to mitigate the effects of underlying inflationary pressures and the volatile Sterling to US Dollar exchange rate, noting c.83% of Group operating costs are denominated in Sterling.

Group operating expenditures of $347.2 million were 12.4% lower than in 2022 ($396.5 million), with unit operating costs (excluding foreign exchange hedging) decreasing to $21.9/Boe (2022: $22.7/Boe). The reduction in operating costs was driven by work programme optimisation across the portfolio, along with higher lease charter credits and lower diesel costs at Kraken.

Other costs of operations of $305.9 million were significantly lower than in 2022 ($487.8 million), driven predominantly by lower gas prices impacting the cost of Magnus-related third-party gas purchases which are sold on of $294.0 million (2022: $452.8 million).

Depletion expense of $292.2 million was 10.6% lower than in 2022 ($327.0 million), mainly reflecting the impact of lower production.

Impairment

In the period, the Group recognised a non-cash net impairment charge of $117.4 million (2022: $81.0 million charge). This charge primarily reflected production and cost profile updates on non-operated assets, partially offset by higher forecast oil prices.

Other income and expenses

The periodic review of the net fair value of the contingent consideration owed by the Group to bp related to the Magnus acquisition led to $69.7 million of non-cash income (2022: $232.5 million non-cash expense), driven by adjustments to the discount rate (2023: 11.3%, 2022: 10.0%) and forward cost assumptions, partially offset by higher forecast long-term oil prices.

A non-cash charge of $32.8 million has been recognised to reflect a net increase in the decommissioning provision of fully impaired non-producing assets (including the Thistle decommissioning linked liability) (2022: non-cash income of $42.8 million).

Also included within other expenses are costs associated with EnQuest's Veri Energy business of $1.6 million (2022: $1.2 million).

Adjusted EBITDA

Adjusted EBITDA was $824.7 million, down 15.8% compared to 2022 ($979.1 million).

Finance costs

The Group's overall finance costs of $230.9 million were 8.6% higher than in 2022 ($212.6 million) primarily driven by higher interest charges, reflecting higher prevailing interest rates, and the unwinding of discounting on contingent consideration related to the acquisition of Magnus and decommissioning and other provisions, partially offset by lower fees associated with the Group's refinancing activities.

Taxation

The 2023 tax charge was impacted by the first full year of the UK EPL at the higher rate of 35% (2022 reflected seven months of UK EPL at 25%).

The $262.6 million total tax charge includes a $77.2 million net EPL charge, which is calculated on a higher profit before tax, and the impact of limited corporation and supplementary corporation tax relief on impairments related to assets where historical deferred tax initial recognition exemptions have already been applied (2022: $244.4 million tax charge).

The Group's effective tax rate for the period was a charge of 113.3% (2022: charge of 120.3%), which primarily reflects the non-deductibility of various cost items under EPL.

EnQuest has recognised UK North Sea corporate tax losses of $2,007.9 million at 31 December 2023 - the reduction in the period reflecting utilisation of ring-fence corporation tax losses against the Group's profits before tax.

Cash flow, net debt and liquidity

Reflecting strong free cash flow generation in 2023 of $300.0 million (2022: $518.9 million), EnQuest net debt at 31 December 2023 amounted to $480.9 million, a $236.2 million year-on-year reduction (31 December 2022: $717.1 million). The Group ended the year with $313.6 million of cash and cash equivalents (2022: $301.6 million), and cash and available facilities totalling $498.8 million (2022: $348.9 million), with the Group's refinancing activities extending the Group's debt maturities to 2027.

With the Bressay-related farm down proceeds offset by a vendor financing facility of $141.4 million (from EnQuest to RockRose, arranged to manage the companies' respective working capital positions) the Bressay transactions were net debt neutral at 31 December 2023. In the first quarter of 2024, EnQuest received a $108.8 million repayment of the vendor financing facility. The remaining amount ($36.3 million) is repayable through net cash flows from the Bressay field, in accordance with the agreed payment schedule. Both EnQuest and RockRose are committed to delivering the Bressay development. In the event, however, that the project does not achieve regulatory approval, there remains an option to deploy the assets on alternative projects. As such, the gain from the transaction is reported within deferred income on the balance sheet.

In the first quarter of 2024, EnQuest repaid the outstanding $140.0 million principal on its RBL facility. The facility remains available to EnQuest for future drawdown.

- Ends -

For further information, please contact:

EnQuest PLC	Tel: +44 (0)20 7925 4900
Amjad Bseisu (Chief Executive)
Jonathan Copus (Chief Financial Officer)
Craig Baxter (Head of Investor Relations)

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 11 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 the London Stock Exchange.

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

Since we set our strategic priorities of 'deliver, de-lever and grow' at the end of 2018, we have made significant progress; consistently delivering against production, operational and cost targets, which in turn has enabled us to generate material free cash flows, even during periods of reduced commodity prices. Against the backdrop of a challenging fiscal environment in the UK, we have reduced EnQuest net debt by more than $1.5 billion since its peak and have aligned outstanding debt maturities in 2027. Now is the time for EnQuest to build on that strong foundation as we pivot to growth during 2024 and initiate our first ever return of capital to shareholders.

During 2023, the Group once again delivered a strong operational and financial performance. Production uptimes were high across the portfolio while maintaining discipline in our cost management and investment decisions drove expenditure lower than 2023 guidance, generating free cash flow of $300.0 million and enabling the reduction of EnQuest net debt to $480.9 million.

From a growth perspective, we have positioned ourselves well to transact by ending 2023 with $498.8 million of liquidity, representing a combination of cash and headroom within our borrowing facilities. The Group has an established track record of executing value-accretive, quick payback acquisitions and, having extended the economic lives of all nine of the assets we have operated by a minimum of ten years, we will look to utilise our differentiated capabilities and advantaged tax position to grow the business through M&A.

We also realised value within the existing portfolio by selling a 15.0% share of both the Bressay licence and the EnQuest Producer FPSO; a transaction which represents an important step in moving the Bressay project forward.

Since 2018, we have materially reduced our absolute Scope 1 and 2 emissions and in 2023, we launched Veri Energy ('Veri'), a wholly owned subsidiary of EnQuest, as the logical next step in the strategic evolution of EnQuest's new energy and decarbonisation ambitions, which are initially focused on the strategically advantaged Sullom Voe Terminal site.

Throughout the year, we reinforced our position as a leading exponent of decommissioning activities, delivering another record year as the most productive well plug and abandonment ('P&A') campaign in the northern North Sea, demonstrating our differentiated capability through an average well plug and abandonment cost which leads our peer group.

Our enhanced business model spans the energy transition, ensuring that through time the transition is managed in a just and sustainable manner. By responsibly managing existing assets, we will continue to contribute to energy security today while advancing our new energy and decarbonisation opportunities through Veri Energy 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 2023, global markets predominantly operated within a price range of $70/bbl to $90/bbl, except for a short period of escalated prices during September. This range reflected softer pricing than that seen during 2022, with a number of economic and geopolitical impacts offsetting each other. 2023 saw an increase in demand for hydrocarbons as global economies continued the path of industrial recovery post-pandemic but the impact on commodity prices was offset by an increase in US shale production of around 1.5 million barrels of oil per day, as well as the emergence of additional incremental non-OPEC supply, predominantly from Brazil, Guyana and Canada. These supply impacts led OPEC to institute production cuts, which drove the September 2023 price spike but which ultimately resulted in a stabilisation of prices towards the end of the year. The geopolitical environment has also caused uncertainty within global markets amid a continuation of the Russia-Ukraine conflict in Europe and escalating tensions in the Middle East as war broke out between Israel and Hamas in October. Supply concerns have escalated and dissipated at various junctures during the fourth quarter of 2023 and continued into 2024 with US-UK missile strikes to protect the safe passage of maritime trade in the Red Sea.

Fiscal uncertainty

Following the introduction, and subsequent amendment, of the Energy Profits Levy ('EPL') during 2022, 2023 represented the first full year of the windfall tax on oil and gas producers, at an increased headline rate of 35%, impacting the Group's profitability. As expected, the EPL has impacted access to capital across the sector, with the most significant on EnQuest being the reduced borrowing base within the Group's RBL facility. Our robust financial performance has enabled EnQuest to accelerate repayments against the RBL, with the 2023 year end drawn balance of $140.0 million being further fully repaid in the first quarter of 2024, while the October 2023 7.00% Sterling retail bond was settled and funds fully drawn under a new $150.0 million term loan facility. Going forward, with a strong balance sheet, we have a fairway of opportunity to grow the business, ahead of debt maturities which are aligned in 2027.

Clearly, a volatile fiscal regime imposes significant challenges on any business and the extension of EPL to 2029 announced in the Spring Budget represented the fourth amendment to UK sector taxation in the last two years. However, EnQuest has a track record of demonstrating resilience, creativity and adaptability and can generate opportunities in such circumstances. 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 that the transfer of assets to EnQuest ownership would increase their relative value to a multiple of that in the hands of existing owners. As such, I am confident we will grow the business through M&A, initially in the UK and then internationally.

Operational performance

EnQuest's average production was in line with the mid-point of guidance at 43,812 Boepd, under-pinned by strong production uptime across the portfolio, including at Kraken where an efficient return to service of the FPSO following the anomalous failure of transformer units limited the impact on production. I was very proud of the EnQuest team which, working alongside the vessel owner, Bumi Armada, reinstated production on a single train basis within 30 days and then full production capacity in around two months.

The well programme at Magnus included the successful completion of the North West Magnus injector well, which came online in May to support the 2022 producer well, alongside two further infill wells which produced first oil in August and December, respectively. Demonstrating EnQuest's differentiated operating capability, Magnus production efficiency in 2023 was 88%, representing a 22% improvement versus 2022.

In Malaysia, average production for the year was 7,437 Boepd, representing a 15% increase over 2022 volumes. This increase includes c.600 Boepd associated with Seligi 1a gas, to which Petronas hold the entitlement, and which is produced and handled by EnQuest in exchange for a gas handling and delivery fee, as well as strong operational performance and production uptime of 90%.

During 2023, we produced c.16 MMboe of our year-end 2022 2P reserves base. This reduction in 2P reserves was partially offset by transfers from 2C resources at Magnus, net of other technical revisions. As such, 2P reserves at the end of the year were around 175 MMboe, down from c.190 MMboe reported at the end of 2022. We continue to have material 2C resources of around 389 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 offshore Malaysia also hold material 2C resources.

The launch of Veri in December 2023 recognises our position at SVT provides a strategically advantaged, sustainable and tangible basis upon which to expand the Group's role in the energy transition; a position which is predicated on a capital-light approach to investment and which was further enhanced by the award of four carbon storage licences in the North Sea Transition Authority's ('NSTA') first UK licensing round.

Our UK decommissioning team continued to demonstrate excellence in the execution of well P&A activities at an average cost of c.£2.5 million per well, significantly below the NSTA benchmark of c.£4.3 million. This programme saw the successful execution of 25 well P&As across the Heather and Thistle fields, exceeding the record for the most prolific multi-asset P&A campaign in the northern North Sea, previously set by EnQuest in 2022.

Financial performance

The Group's adjusted EBITDA and statutory gross profit decreased by 15.8% to $824.7 million and 17.2% to $540.7 million, respectively, reflecting lower realised oil prices and production. Operating costs for the year of $347.2 million were 12.4% lower than 2022, primarily due lower diesel costs and higher lease charter credits associated with the unplanned downtime at Kraken. Unit operating costs decreased 3.5% to $21.9/Boe, reflecting the impacts on costs noted above. Cash generated by operations decreased to $854.7 million, down by 16.7% compared to 2022, although free cash flow generation remained robust, delivering $300.0 million.

The Group's continued solid financial and operating performance during the year drove further strengthening of the balance sheet and enabled the focus of the business to pivot to growth in 2024. We are also delighted to announce our first shareholder return programme and intend to deploy $15.0 million of capital in a share buyback programme during 2024.

Environmental, Social and Governance

The health, safety and wellbeing of our employees remains our top priority. In 2023, we delivered another upper quartile Lost Time Incident ('LTI') frequency1 rate but were disappointed to see three LTIs during the year. We remain laser focused on SAFE results with no harm to our staff and contractors and have engaged in a programme of intervention, assessing root causes of incidents and working closely with the contractors involved to ensure that everyone is aligned with our safety culture, trained on equipment and procedures and empowered to stop a task should a safer method be identified.

As outlined earlier, we have made excellent progress in reducing absolute Scope 1 and 2 emissions in recent years, with the Group's CO2 equivalent emissions reduced by 23% since 2020 and the UK's emissions down by c.41% since 2018. This progress is significantly ahead of the Group's targeted reductions and those set by the UK Government's North Sea Transition Deal, providing a strong foundation for our commitment to reach net zero by 2040. Looking ahead, the Group has approved investments designed to reduce future carbon emissions and operating costs across the portfolio, including the new stabilisation facility and power generation projects at SVT and the potential gas tie-back solution from Bressay to Kraken. 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 Non-Executive Directors Howard Paver, Carl Hughes and John Winterman stepping down, to be succeeded by Mike Borrell and Karina Litvack, although Karina unfortunately had to resign her position due to a conflict. I would like to thank Howard, Carl, John and Karina for their contributions, and I look forward to working with the refreshed Board as we execute on our growth strategy.

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)

2024 performance and outlook

Production performance to the end of February was 44,498 Boepd. Our full-year net production guidance of between 41,000 and 45,000 Boepd includes the impacts from drilling campaigns at Magnus, PM8/Seligi and Golden Eagle and required maintenance activities across the portfolio.

Operating costs are expected to be approximately $415.0 million, while capital expenditure is expected to be around $200.0 million, with decommissioning expenditure expected to total approximately $70.0 million.

Longer-term development

Our strategy and business model have evolved to align to our aims of delivering value-driven growth and establishing EnQuest as a key player in a just energy transition. We have established a track record of executing acquisitions and optimising asset lives, underpinned by our operating capabilities and the transactional flexibility which is derived from our improved liquidity.

Our position as a top quartile operator, 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 also believe that our core capabilities and top quartile operating performance can be replicated across other geographies as we seek to grow and diversify internationally.

2023 was a year of continued strong performance for the Group which was achieved with the support of all our stakeholders; our people, shareholders, investors, lenders, partners and suppliers. I thank all for their contributions throughout 2023 and I am excited about delivering EnQuest's next growth phase during this pivotal year.

Operational review

Upstream operations

2023 Group performance summary

Production of 43,812 Boepd reflected improved performances at Magnus and at PM8/Seligi, strong production uptimes across the operated portfolio and the Group's investment in low-cost, quick-payback drilling and wellwork campaigns, partially offsetting the impact of natural field declines.

Magnus

2023 performance summary

2023 production of 15,933 Boepd was 26% higher than the 2022 figure of 12,641 Boepd, driven by significantly improved production efficiency of 88% (2022: 66%) following improvements to rotating equipment performance, including gas compressors and power generation units. The Group executed an extensive wellwork programme, with three wells returned to service following P seal repair/replacement works, execution of a perforation scope and the completion of an infill drilling programme which included the North West Magnus injector in May and two further infill wells which came online in August and December, respectively. In addition, slot recovery activity continued to enable the delivery of future infill drilling opportunities, with the completion of the B6 well plug and abandonment ('P&A') during July 2023.

The planned annual maintenance shutdown was completed in 20 days, versus the original planned duration of 24 days, with all major scopes executed. The shutdown involved 10,000 manhours of work being completed with zero lost time incidents.

2024 outlook

The five-yearly rig recertification of the Magnus platform rig commenced in early January and is expected to run until the second quarter of 2024, with infill drilling activity to recommence thereafter. 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 minimise platform vulnerability. It is anticipated that two wells will be drilled in the second half of 2024, with the expectation that Magnus production will be higher than 2023. With 2C resources of c.28 MMboe, Magnus offers the Group significant low-cost, quick payback drilling opportunities in the medium term.

Kraken

2023 performance summary

Average net production in 2023 was 13,580 Boepd (2022: 18,394 Boepd), which is reflective of high uptime before and after the anomalous failure of HSP transformer units during May. Working alongside the vessel owner, Bumi Armada, the EnQuest asset team exemplified differentiated operational capability by limiting the impact of this outage, resuming production on a phased basis within 30 days of the outage and then, through the refurbishment/rebuild and reinstatement of transformer units, returned Kraken to full production in early-August. Subsequently, the Group oversaw a return to top quartile performance, with the Floating, Production, Storage and Offloading ('FPSO') delivering production efficiency and water injection efficiency of 98% and 99%, respectively, for the final four months of the year. For the full year 2023, production efficiency was 86% (2022: 93%) and water injection efficiency was 85% (2022: 93%).

Production in the second half of the year benefited from the removal of two planned periods of single train operations, with the Group having executed maintenance work while production at the FPSO was shut-in. In addition, delivery and deployment of new HSP transformer units has provided increased resilience to production capacity, with further HSP and water injector transformer replacements planned during 2024.

The Group continues to optimise Kraken cargo sales into the shipping fuel market, with Kraken oil a key component of International Maritime Organization ('IMO') 2020 compliant low-sulphur fuel oil while avoiding refining-related emissions.

2024 outlook

No shutdown is planned during 2024 but it is expected that a ten-day period of single processing train operations will be undertaken in order to execute safety-critical maintenance work.

The Group has procured a mobile offshore drilling unit ahead of a planned return to drilling at Kraken during 2025. EnQuest will purchase selected long lead equipment during 2024 required to facilitate the two-well sidetrack 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, while Kraken production will be subject to natural decline in 2024.

Golden Eagle

2023 performance summary

2023 net production was below the Group's expectations at 4,199 Boepd (2022: 6,323 Boepd), with asset production efficiency in excess of 90% (2022: 95%).

Following the arrival of the drilling rig in August 2023, drilling of the first well in the 2023/24 platform drilling programme commenced in October 2023 and the well was brought online in January 2024. This is the first well of an anticipated four-well programme, which is due to be completed in mid-2024.

2024 outlook

The operator has scheduled a shutdown of around one week in the summer of 2024, with subsequent major shutdowns expected to be required every two to three years.

Other North Sea assets

2023 performance summary

Production in 2023 averaged 2,663 Boepd (2022: 3,442 Boepd), largely in line with expectations and reflecting strong uptime of 83% (2022: 87%) at the Greater Kittiwake Area.

At Alba, performance continued largely in line with the Group's expectations.

Work continued towards the development of the wider Kraken area, including a Bressay gas tie-back solution and an early production solution project at Bressay with RockRose Energy now a joint venture partner on the Bressay project, with regulatory approval granted in March 2024.

2024 outlook

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

At Bressay, EnQuest continues to actively explore further farm-down opportunities and development planning of the asset, with the aim to utilise its expertise in heavy oil developments to access the c.115 MMboe of 2C resources. In 2024, the Group aims to progress the tie-back of the Bressay field's gas cap to Kraken, displacing diesel that currently powers Kraken operations.

PM8/Seligi

2023 performance summary

Average production of 7,437 Boepd was 15% higher than 2022. This increase includes 604 Boepd associated with Seligi 1a gas, to which Petronas holds the entitlement, and which is produced and handled by EnQuest in exchange for a gas handling and delivery fee, as well as strong operational performance and production uptime of 90% (2022: 86%).

Following the drilling of the commitment well at Block PM409, the well was plugged and abandoned dry. Following confirmation from Petronas that all well requirements had been met by EnQuest, no further drilling is planned for PM409.

2024 outlook

A two-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. To further improve compressor reliability, turbine control panel upgrade is planned for the second train at the end of the third quarter.

The Group plans to drill three infill wells and deliver three well workovers, with six wells to be plugged and abandoned. These well programmes will mobilise at the end of the first quarter of the year.

EnQuest has significant 2P reserves and 2C resources of c.28 MMboe and c.80 MMboe, respectively, 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.

Decommissioning

Performance summary

Within EnQuest's decommissioning team, 2023 represented another year of record-breaking delivery, enhancing the Group's strong track record of executing multi-asset abandonment campaigns. As the Thistle and Heather project teams look ahead to the culmination of the respective well plug and abandonment ('P&A') campaigns, preparation is underway for the 2025 removals programmes at these two major platforms in the North Sea.

Well decommissioning

At both the Heather and Thistle fields, the extensive programme of well P&A continued apace throughout the year. Thistle successfully abandoned 13 wells whilst Heather completed 12 wells by year end, while a further well at each asset was partially completed as at 31 December 2023. In addition to the completion of 25 well abandonments across the two platform rigs, the Thistle project team implemented a third activity string, in the form of a hydraulic workover unit, to accelerate the recovery of conductors on available wells. This resulted in seven wells being abandoned to the final stage of the well P&A process, which focuses on removing the surface infrastructure and ensuring the well poses no future environmental or safety risks, reducing the critical path of the main rig activity and resulting running costs of the asset.

Both the Thistle and Heather project teams are targeting completion of their well P&A campaigns by the end of the first quarter of 2025 and remain on target to permanently disembark the respective platforms later that year.

Throughout 2023, EnQuest has also progressed the detailed engineering work on the subsea wells at Alma Galia, Dons and Broom, while continuing to discuss the future work programmes with the North Sea Transition Authority.

Preparation for removal

Beyond well P&A activity, the Heather project team plans to execute multiple work scopes in 2024, including the flushing of pipelines, preparing the Broom riser for decommissioning and other engineering and cleaning scopes.

In the second half of the year, the contract award for the disposal of the Heather topsides was awarded, while the removal of the platform topsides will be completed in a single lift in 2025 utilising the Pioneering Spirit heavy lift vessel ('HLV').

At Thistle, the project team demonstrated its capability by delivering multiple key scopes. Subsea campaigns covering essential IRM activities, preparatory work for conductor removal and the flushing and final disconnection of pipeline PL166 were all completed successfully. The team also engaged a conductor pulling unit, which enabled simultaneous P&A operations alongside the main rig.

Following an extensive commercial exercise, EnQuest awarded the contract for the Thistle topsides and jacket Engineering, Preparation, Removal and Disposal ('EPRD') works to Saipem. The removal operations are due to take place from 2026 onwards and will see all 32 modules of the Thistle platform lifted onto the semi-submersible heavy lift vessel S7000 and returned to shore in four separate voyages.

Throughout 2024, the project teams across Heather and Thistle will be focused on the engineering required to prepare for the heavy lift operations as well as exploring opportunities to further optimise schedule, cost and delivery targets where possible.

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

Infrastructure - Midstream

Within its Midstream directorate, EnQuest operates the Sullom Voe Terminal ('SVT') on Shetland and around 1,000km of pipelines.

Safe, stable operations

Throughout 2023, the Group continued to deliver safe, stable and effective operations for both East of Shetland and West of Shetland oil and gas, delivering 100% uptime for both oil streams, and 99% uptime for West of Shetland gas. In addition, the Sullom Voe Terminal ('SVT') power station achieved 100% power delivery throughout the period. The terminal, which celebrated its 45th anniversary of oil production in November 2023, also achieved four million man hours Lost Time Incident ('LTI') free during the third quarter of 2023.

Decarbonisation

The Group is focused on right-sizing SVT for future operations. During 2023, EnQuest successfully matured and gained support for two strategic projects to connect the terminal to the UK's electricity grid and the construction of new stabilisation facilities ('NSF'). Completion of the NSF is expected to enable the Group to meet the North Sea Transition Authority ('NSTA') target of zero routine flaring obligations by 2030 while, taken together, delivery of these two projects is expected to result in a 90% reduction in overall emissions from SVT and the Engie-operated Sullom Voe power station. The anticipated reduction in future emissions set out within these projects led to EnQuest's SVT operation being shortlisted for a 2023 Offshore Energies UK Decarbonisation Award.

EnQuest has awarded a strategic contract for the phased partial decommissioning of the existing oil stabilisation and processing facilities. This will create space onsite for future new energy projects such as carbon storage, the production of green hydrogen and offshore electrification.

People and community

The Group has an established apprentice programme at SVT, with three apprentices successfully graduating in 2023. Further, EnQuest renewed a four-year programme which enables apprentices to be sponsored at the terminal, with the adoption of one apprentice into the programme due to his site-based experience. Separately, the Group launched a new graduate programme in 2023, with two graduates recruited into SVT, one of whom is a resident of Shetland. Also in 2023, the programme's most recent graduate attained Chartered Engineer status with the Institution of Chemical Engineers.

Key projects

Carbon capture and storage ('CCS')

Veri Energy is seeking to develop a flexible carbon storage solution that can transport and permanently store up to 10mtpa of CO2 from isolated emitters in the UK and Europe. CO₂ captured by emitters will be transported via ship to SVT from where it will be transported via repurposed pipeline infrastructure for permanent geological storage in depleted oil and gas reservoirs.

In August 2023, EnQuest successfully secured carbon storage licences as part of the first round of UK carbon sequestration licences issued by the North Sea Transition Authority ('NSTA'). The licences areas CS013, CS014, CS015 and CS016 are some 99 miles northeast of Shetland and include fields currently operated by EnQuest, the Magnus and Thistle fields, as well as the non-operated Tern, Otter and Eider fields. These sites are large, well-characterised deep storage formations connected by significant existing infrastructure to the Sullom Voe Terminal on Shetland.

Green hydrogen

Veri Energy is progressing evaluation of a 50 megawatt green hydrogen project at Sullom Voe. In February 2024, Veri received an award of £1.74 million in grant funding from the UK government's Net Zero Hydrogen Fund ('NZHF') to support a front-end engineering and design study for the project.

Renewable power

Veri Energy is also exploring the potential to develop renewable power to provide electrification for existing and prospective oil and gas facilities.

Financial review

Introduction

During December, EnQuest announced the sale of a 15.0% equity share in the Bressay licence and the EnQuest Producer FPSO for a total consideration of £46.0 million (c.$57.0 million). Subsequently, the Group received $85.6 million for a 15.0% farm-down of capital items identified as suitable for use on the Bressay development. Through these transactions the Group has realised near-term value, expecting to yield c.$58.0 million post-tax cash flow in 2024, and delivered an important step in moving the project forward.

The Group's improved balance sheet, liquidity position and significantly advantaged tax position means EnQuest is well placed to pursue growth opportunities and deliver its first program of shareholder returns, committing to a $15.0 million buy back that will be completed during 2024.

Income statement

Revenue

Group production averaged 43,812 Boepd, with strong uptimes across the portfolio and investment in low-cost, quick-payback drilling and wellwork campaigns partially offsetting the impact of natural field declines (2022: 47,259 Boepd).

Realised losses on commodity hedges totalled $11.3 million (2022: losses of $203.7 million). Unrealised gains on these contracts (from mark-to-market movements) totalled $28.5 million (2022: unrealised gains of $14.5 million).

Revenue from the sale of condensate and gas, totalling $339.0 million (2022: $514.2 million), primarily relates to the onward sale of third-party gas that was not required for injection activities at Magnus. The contribution from these third-party gas volumes is offset in Cost of sales. Tariffs and other income generated a further $3.8 million (2022: $11.0 million), including income from the transportation of Seligi associated gas.

Cost of sales


	2023 $ million	2022 $ million
Production costs	308.3	347.8
Tariff and transportation expenses	41.7	43.3
Realised (gain)/loss on derivatives related to operating costs	(2.8)	5.4
Operating expenditures1	347.2	396.5
Charge/(credit) relating to the Group's lifting position and inventory	(4.2)	(15.6)
Other cost of operations	305.9	487.9
Depletion of oil and gas assets	292.2	327.0
Other cost of sales	5.7	4.9
Cost of sales	946.8	1,200.7
Unit operating cost^2,3	$/Boe	$/Boe
- Production costs	19.3	20.2
- Tariff and transportation expenses	2.6	2.5
Average unit operating cost	21.9	22.7

Notes:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP Measures' starting on page 65

2 Calculated on a working interest basis

3 Excludes realised (gain)/loss on derivatives related to operating costs

The Group demonstrated effective cost control to mitigate the effects of underlying inflationary pressures, through extensive supplier engagement and agreeing fixed rate contracts for certain services, and the strengthening Sterling to US Dollar exchange rate with the Group's foreign exchange hedging delivering gains of $5.2 million in the period, noting c.83% of Group operating costs are denominated in Sterling.

Group operating costs of $347.2 million were 12.4% lower than in 2022 ($396.5 million), with unit operating costs (excluding foreign exchange hedging) decreasing to $21.9/Boe (2022: $22.7/Boe). The reduction in operating costs was driven by work programme optimisation across the portfolio, higher lease charter credits and lower diesel costs at Kraken.

Depletion expense of $292.2 million was 10.6% lower than in 2022 ($327.0 million), mainly reflecting the impact of lower production.

Impairment

Other income and expenses

The Group has recognised net income in the period $39.3 million (2022: net expense of $152.4 million).

The periodic review of the net fair value of the contingent consideration owed to bp relating to the Magnus acquisition led to $69.7 million of non-cash income (2022: $232.5 non-cash expense), driven by adjustments to the discount rate (2023: 11.3%, 2022: 10.0%) and forward cost assumptions, partially offset by higher forecast oil prices.

Against a backdrop of inflationary pressures and Sterling strengthening against the US Dollar, a non-cash charge of $32.8 million has been recognised to reflect a net increase in the decommissioning provision of fully impaired non-producing assets (including the Thistle decommissioning linked liability) (2022: non-cash income of $42.8 million, driven by an increase in the discount rate applied and Sterling weakening against the US Dollar).

Also included within other expenses are costs associated with EnQuest's Veri Energy business of $1.6 million (2022: $1.2 million).

Adjusted EBITDA¹


	2023 $ million	2022 $ million
Profit from operations before tax and finance income/(costs)	456.2	411.9
Unrealised hedge gain	(28.5)	(14.5)
Depletion and depreciation	298.3	333.2
Impairment	117.4	81.0
Net other (income)/expense	(33.7)	183.1
UKA forward purchase losses	3.8	4.9
Change in well inventories	(0.6)	0.8
Net foreign exchange loss/(gain)	11.8	(21.3)
Adjusted EBITDA1	824.7	979.1

Note:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP Measures' starting on page 65

Adjusted EBITDA was $824.7 million, down 15.8% compared to 2022 ($979.1 million).

Finance costs

The Group's overall finance costs of $230.9 million were 8.6% higher than in 2022 ($212.6 million).

The net effect from the reduction in the Group's outstanding loans and borrowings and higher prevailing interest rates, resulted in a higher overall interest charge for 2023 of $89.7 million (2022: $77.2 million) - although this was partially offset by lower fees associated with the Group's refinancing activities (2023: $7.9 million; 2022: $35.3 million).

Finance charges were also higher due to the unwinding of discounting on contingent consideration related to the acquisition of Magnus (2023: $58.9 million; 2022: $36.4 million) and decommissioning and other provisions (2023: $25.4 million; 2022: $17.8 million).

Other charges included in finance costs are lease liability interest of $43.8 million (2022: $39.2 million) and other financial expenses of $5.3 million (2022: $6.8 million), primarily being the cost for surety bonds to provide security for decommissioning liabilities.

Profit/loss before tax

Reflecting the movements above, the Group's profit before tax of $231.8 million was $28.6 million higher than 2022 ($203.2 million).

Taxation

The 2023 tax charge was impacted by the first full year of the UK EPL at the higher rate of 35% (2022 reflected seven months of UK EPL at 25%).

The $262.6 million total tax charge includes a $77.2 million EPL charge, which is calculated on a higher profit before tax, and the impact of limited corporation and supplementary corporation tax relief on impairments related to assets where historical initial recognition exemptions for deferred tax have already been applied (2022: $244.4 million tax charge, which included the initial recognition of a $178.3 million non-cash deferred tax liability associated with the EPL partially offset by a credit for the non-cash recognition of undiscounted deferred tax assets of $127.0 million).

The Group's effective tax rate for the period was a charge of 113.3% (2022: charge of 120.3%).

Due to this recognised tax loss position, no significant corporation tax or supplementary charge is expected to be paid on UK operational activities for the foreseeable future.

The Group paid its 2022 EPL charge in October 2023 and is expected to make further EPL payments in October each year 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.

Profit/loss for the year

The Group's total loss after tax was $30.8 million (2022: loss of $41.2 million). The high effective tax rate was primarily driven by the current tax impact of EPL, reflecting its high level of non-deductible expenditures related to financing and decommissioning costs, and limited corporation and supplementary corporation tax relief on impairments related to assets where historical initial recognition exemptions have been applied.

Earnings per share

The Group's reported basic loss per share was 1.6 cents (2022: loss of 2.2 cents) and reported diluted loss per share was 1.6 cents (2022: loss of 2.2 cents).

Cash flow, EnQuest net debt and liquidity


	$ million
EnQuest net debt 1 January 2023	(717.1)
Net cash flows from operating activities	754.2
Cash capital expenditure	(152.2)
Magnus profit share payments	(65.5)
Golden Eagle contingent consideration payment	(50.0)
Finance lease payments	(135.7)
Proceeds from farm-down	141.4
Vendor financing facility	(141.4)
Net interest and finance costs paid	(100.0)
Other movements, including net foreign exchange on cash and debt	(14.6)
EnQuest net debt 31 December 20231	(480.9)

Note:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP Measures' starting on page 65

The Group's reported net cash flows from operating activities were $754.2 million, down 19.0% compared to 2022 ($931.6 million). The overall reduction was primarily driven by lower revenue, partially offset by lower cash opex.

In line with guidance, the Group's reported net cash flows used in investing activities increased $101.5 million to $262.7 million (2022: $161.2 million). This increase principally reflects: higher capital expenditures of $152.2 million (2022: $115.8 million), which primarily related to Magnus, Golden Eagle and Malaysia well campaigns and Sullom Voe Terminal projects; the final Golden Eagle Contingent consideration payment ($50.0 million) and an additional $19.5 million of Magnus profit share payments (2023: $65.5 million; 2022: $46.0 million).

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


	Year ended 31 December 2023 $ million	Year ended 31 December 2022 $ million
North Sea	124.2	85.5
Malaysia	21.0	26.5
Exploration and evaluation	7.0	3.8
	152.2	115.8

EnQuest received $108.8 million repayment of the vendor financing facility. The remaining amount ($36.3 million) is repayable through net cash flows from the Bressay field in accordance with the agreed payment schedule. In the event, however, that the project does not achieve regulatory approval, there remains an option to deploy the assets on alternative projects. As such, proceeds from the transaction are reported within deferred income on the balance sheet.

The Group utilised $478.6 million of cash in financing activities (2022: $731.2 million) - including further net repayments of the Group's loans and borrowings totalling $237.1 million (2022: $479.8 million). In this figure, $260.0 million of the Group's RBL facility was repaid, the October 2023 7.00% Sterling retail bond was settled (£111.3 million) and funds were fully drawn under a new $150.0 million term loan facility.

Associated with these borrowings, interest costs totalled $105.9 million (2022: $103.4 million). In the year, $135.7 million was also paid on finance leases (2022: $148.0 million).


	EnQuest net debt¹
	31 December 2023 $ million	31 December 2022 $ million
Bonds	474.7	600.7
RBL	140.0	400.0
Term Loan	150.0	0.0
SVT working capital facility	29.8	12.3
Vendor loan facility	-	5.7
Cash and cash equivalents	(313.6)	(301.6)
EnQuest net debt	480.9	717.1

Note:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP Measures' starting on page 65

The Group ended the year with $313.6 million of cash and cash equivalents (2022: $301.6 million), and cash and available facilities totalling $498.8 million (2022: $348.9 million), with the Group's refinancing activities extending the Group's debt maturities to 2027.

In the first quarter of 2024, EnQuest repaid the outstanding $140.0 million principal on its RBL facility. The facility remains available to EnQuest for future drawdown.

Balance sheet

The Group's strong cash generation, improved liquidity position, including extended maturities of its available debt facilities, and UK tax advantage, means EnQuest is well positioned to continue delivering its foundation programmes of capital investment - whilst also pursuing transformational North Sea and International production acquisitions, and delivering its first program of shareholder returns.

Assets

Total assets at 31 December 2023 reduced by 6.4% to $3,765.8 million (2022: $4,024.3 million). This movement is primarily driven by: a reduction of $165.7 million in the Group's deferred tax asset (largely reflecting the impact of utilising ring-fence corporation tax losses in the period (see note 7)); lower net PP&E of $180.2 million, including a non-cash net impairment charge of $117.4 million (see note 10); and a partial offset from recognition of the Bressay vendor financing facility receivable of $145.1 million (see note 19).

Liabilities

Total liabilities reduced by 6.5% to $3,309.0 million (2022: $3,540.0 million) - the Group continuing to make material repayments of its debt, resulting in a materially lower carrying value of $775.2 million (2022: $1,000.3 million) (see note 18).

Contingent consideration payments related to the acquisitions of Magnus and Golden Eagle totalled $115.5 million (2022: $46.0 million for Magnus, nil for Golden Eagle), and a net change in the fair value estimate for Magnus resulted in a lower outstanding contingent consideration estimate of $507.8 million (2022: $636.9 million) (see note 22).

Offsetting these reductions are a $57.7 million net increase in the Group's current and deferred tax liabilities - UK EPL driving a higher income tax payable provision of $185.5 million (2022: $39.2 million payable) offset by a $88.7 million lower deferred tax liability of $77.6 million (2022: $166.3 million).

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 28 of the financial statements.

Going concern disclosure

In recent years, given the prevailing macroeconomic and fiscal environment, the Group has prioritised deleverage - reducing gross debt (excluding leases) by c. $1.4 billion since 2017 to $794.5 million at 31 December 2023. During 2023, EnQuest net debt was reduced by $236.2 million (to $481.1 million) and the Group strengthened its net debt to adjusted EBITDA ratio to 0.6x, close to EnQuest's target of 0.5x. In this 12-month period, cash and available facilities increased by $149.9 million, to $498.8 million at 31 December 2023, and medium-term liquidity is secured, with all the Group's debt maturities now in 2027.

Against this robust backdrop, EnQuest continues to closely monitor and manage 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.

The Group's latest approved business plan underpins management's base case ('Base Case') and is in line with the Group's production guidance using oil price assumptions of $80.0/bbl for 2024 and $75.0/bbl for 2025.

A reverse stress test has been performed on the Base Case indicating that an average oil price of c.$63.0/bbl over the going concern period maintains covenant compliance, reflecting the Group's strong liquidity position.

The Base Case has also been subjected to further testing through a scenario reflecting the impact of the following plausible downside risks (the 'Downside Case'):

· 10% discount to Base Case prices resulting in Downside Case prices of $72.0/bbl for 2024 and $67.5/bbl for 2025;

· Production risking of 5.0%; and

· 2.5% increase in operating, capital and decommissioning expenditure

The Base Case and Downside 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.

After making appropriate enquiries and assessing the progress against the forecast and projections, 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 2027. The viability assumptions are consistent with the going concern assessment, with the additional inclusion of an oil price of $75.0/bbl for 2026 and 2027 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 27 March 2024, 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 27. 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. Under the Group's Base Case 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 March 2027.

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. 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, from 1 April 2024 the Directors have hedged a total of 5.0 MMbbls for the remainder of 2024, with 4.1MMbbls through the use of put options with an average floor price of c.$60/bbl and 0.9MMbbls through swaps at an average price of $86/bbl, and 1.6 MMbbls in 2025 using 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. In the 2023 Autumn Statement on 22 November, the UK Government confirmed that they will bring in legislation for the Energy Security Investment Mechanism and have agreed to index link the trigger floor price to CPI from April 2024. The Government also announced that once the decarbonisation allowance of 80% against EPL is withdrawn (currently in March 2028), that they will replace this with a new allowance at the same effective rate against the industry tax regime. In March 2024, the UK Government announced that the sunset clause for EPL would be extended by a year to 31 March 2029, although no date has yet been set for when this will be legislated. Further fiscal changes could be enacted should there be a change in UK Government at the next general election. The Group will continue to monitor developments and any potential related impacts.

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 dates of July 2027 for the $150.0 million term loan and November 2027 for the $305.0 million high yield bond and the £133.3 million retail bond, provide a material level of funding throughout the assessed viability period ending March 2027. The Group has continued to prioritise debt reduction from free cash flows as evidenced with the RBL being fully repaid in the first quarter of 2024, materially ahead of schedule.

In assessing viability, the Directors recognise that in a Downside Case limited additional liquidity would be required, which may necessitate limited mitigations, such as working capital management, amendments to capital work programmes, asset farm downs or other financing options. Given the extended duration of the viability period, the Directors believe such measures can be executed successfully in the necessary timeframe to 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 March 2027. 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 Board also periodically reviews (with senior management) 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') 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 Sustainability 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, the evolution of the fiscal regime, 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 decarbonisation strategy through the Infrastructure and New Energy business, which was established in 2021 and launched as Veri Energy, a wholly owned subsidiary of the Group, in 2023. 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' (being those assets no longer able to earn an economic return as a result of changes associated with the transition to a low-carbon economy).

Within the Group's RMF, the Sustainability 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 levels (see diagram below). These Risk Bowties are periodically reviewed to ensure they remain fit for purpose.

The Board, supported by the Audit Committee and the Sustainability Committee, has reviewed the Group's system of risk management and internal control for the period from 1 January 2023 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 Sustainability Committee meeting in support of this review.

Near-term and emerging risks

As outlined previously, the Group's RMF is embedded at 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, and how these ultimately impact on the enterprise-level risk and their associated 'Risk Bowties'. 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 Sustainability Committee, which are now integrated into the Group's internal audit programme for review. During the year, five Risk Bowties were reviewed, ensuring that all 19 of the Group's identified risks have been reviewed within the targeted cycle.

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. Additional information can be found in the Group's Task Force on Climate-related Financial Disclosures.

CLIMATE CHANGE

Risk

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 on pages 53 to 60.

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 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 Sustainability Committee of the Board. An emissions reduction of 24% was achieved over this three-year period 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 Veri Energy business in 2023, 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'.

Other near-term risks being monitored

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.

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 Energy Profits Levy ('EPL') introduced in the Autumn Budget Statement 2022 materially impacted the Group's RBL borrowing base and associated amortisation schedule. In the 2023 Autumn Budget Statement on 22 November, the UK Government confirmed that they will bring in legislation for the Energy Security Investment Mechanism and have agreed to index link the trigger floor price to CPI from April 2024. The Government also announced that once the decarbonisation allowance of 80% against EPL is withdrawn in March 2028, that they will replace this with a new allowance at the same effective rate against the permanent tax regime. Further fiscal changes could be enacted should there be a change in UK government at the next general election. The Group will continue to monitor developments and any potential related impacts. 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 its 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 which of the Group's KPIs could be impacted by this risk (see page 03) for an explanation of the KPI symbols); 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 20 and 'Subsurface risk and reserves replacement' on page 23), and/or further changes in the fiscal environment (see 'Financial' risk on page 21 and 'Fiscal risk and government take' on page 24), 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.

Health, SafetY and Environment ('HSE')

Risk

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.

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 2023, EnQuest's Lost Time Incident frequency rate¹ ('LTIF') of 0.52 and three hydrocarbon releases, reported on page 28, challenged this objective. The lost time injuries were all associated with routine repetitive tasks across three assets. The root causes have been assessed and the Group is working closely with the contractors involved to ensure that everyone is aligned with EnQuest's safety culture, trained on equipment and procedures and empowered to stop a task should a safer method be identified. None of the hydrocarbon releases had common root causes and occurred at three different locations and, after thorough investigation, no systemic failure was identified within EnQuest systems.

The incidents occurred in the first part of the year and, since then, corrective and preventative actions have been implemented, no further LTIs or hydrocarbon release occurred in the remainder 2023.

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's HSE Policy is fully integrated across its operated sites and this enables a consistent focus on HSE. There is a strong assurance programme in place to ensure that the Group complies with its policy and principles and regulatory commitments.

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. The Group-aligned HSE Continuous Improvement Plan promotes 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 Sustainability Committee. During 2023, 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.

Potential impact

Medium (2022 Medium)

Likelihood

Medium (2022 Medium)

Change from last year

Reflecting the hazards associated with oil and gas development and production in harsh environments, the potential impact has increased albeit the likelihood of this risk has not changed. Through our HSE processes, there is continuous focus on the management of the barriers that prevent hazards occurring. 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 and is achieved by working closely and openly with contractors, verifiers and regulators to identify potential improvements through an active assurance process and implement plans to close any gaps in a timely manner.

Risk appetite

Low (2022 Low)

Oil and gas prices

Risk

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.

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 ('RBL') 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 (see page 59) and the terms of the Group's reserve based lending facility, which requires hedging of EnQuest's entitlement sales volumes (see page 59). From 1 April 2024, the Group had hedged approximately 6.6 MMbbls for 2024 and 2025. 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.

Potential impact

High (2022 High)

Likelihood

High (2022 High)

Change from last year

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.

Risk appetite

Medium (2022 Medium)

PRODUCTION

Risk

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.

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.

Potential impact

High (2022 High)

Likelihood

Medium (2022 Medium)

Change from last year

There has been no material change in the potential impact or likelihood. The Group met its 2023 production guidance and continues to focus on key maintenance activities during planned shutdowns and procuring a stock of critical spares to support facility uptime.

Risk appetite

Low (2022 Low)

FINANCIAL

Risk

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 and 16.

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 2023, the Group's strong free cash flow generation drove a $236.2 million reduction in EnQuest net debt to $480.9 million at 31 December 2023, with an EnQuest net debt to adjusted EBITDA ratio of 0.6x. During the year, EnQuest also entered into a term loan facility of up to $150 million and repaid its 2023 retail bonds, thus extending and aligning all debt maturities to 2027. At 27 March 2024, the Group's RBL facility was undrawn following repayments totalling $140.0 million in the first quarter of 2024, 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.

Potential impact

High (2022 High)

Likelihood

High (2022 High)

Change from last year

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 and entered into a new term facility in 2023, which extends the Group's debt 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 disclosure on page 15).

Factors such as climate change, other 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 upward 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.

Risk appetite

Medium (2022 Medium)

COMPETITION

Risk

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.

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 $2.0 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.

Potential impact

High (2022 High)

Likelihood

High (2022 High)

Change from last year

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.

Risk appetite

Medium (2022 Medium)

IT SECURITY AND RESILIENCE

Risk

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.

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, Viva Engage 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 (including internal audit reviews) and implementing improvements as necessary has continued during 2023.

Potential impact

Medium (2022 Medium)

Likelihood

High (2022 Medium)

Change from last year

The current geopolitical environment and the increased number of cyber attacks against companies in the sector in which the Group operates, and beyond, increases the likelihood of attempted cyber incursions against EnQuest. The Group continues to evolve its IT systems and resilience to mitigate this. There is no change to the impact of this risk.

Risk appetite

Low (2022 Low)

PORTFOLIO CONCENTRATION

Risk

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.

Appetite

Although the extent of portfolio concentration is moderated by production generated in Malaysia, the majority of the Group's assets remain 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.

Potential impact

High (2022 High)

Likelihood

High (2022 High)

Change from last year

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.

Risk appetite

Medium (2022 Medium)

subsURFAce risk and reserves replacement

Risk

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

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.

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

Potential impact

High (2022 High)

Likelihood

Medium (2022 Medium)

Change from last year

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.

Risk appetite

Medium (2022 Medium)

project execution and delivery

Risk

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

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.

Within Veri 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.

Potential impact

Medium (2022 Medium)

Likelihood

Low (2022 Low)

Change from last year

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.

Risk appetite

Medium (2022 Medium)

fiscal risk and government take

Risk

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.

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 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.

Potential impact

High (2022 High)

Likelihood

High (2022 Medium)

Change from last year

There has been no material change in the potential impact; however, the likelihood has increased given the implementation of, and subsequent change to, the 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.

Risk appetite

Medium (2022 Medium)

international business

Risk

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.

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.

Potential impact

Medium (2022 Medium)

Likelihood

Medium (2022 Medium)

Change from last year

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

Risk appetite

Medium (2022 Medium)

Joint venture partners

Risk

Failure by joint venture parties to fund their obligations.

Dependence on other parties where the Group is non-operator.

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.

Potential impact

Medium (2022 Medium)

Likelihood

Low (2022 Low)

Change from last year

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

Risk appetite

Medium (2022 Medium)

reputation

Risk

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.

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 undertake 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.

Potential impact

High (2022 High)

Likelihood

Low (2022 Low)

Change from last year

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

Risk appetite

Low (2022 Low)

human resources

Risk

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.

Appetite

As a 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 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 is therefore 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 each 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 feedback is frequently sought to understand employees' views on areas, including diversity and inclusion and wellbeing in order to develop appropriate action plans. Although it was anticipated that fewer young people may join the industry due to climate change-related factors, 2023 saw a rise in the number of young professionals joining EnQuest. We believe the Group's decarbonisation ambitions as well as the graduate programme, introduced in 2023, has contributed to this change. EnQuest aims to attract and sustain the best talent, recognising the value and importance of diversity. The emphasis around improved diversity in the Group's management and leadership is a main focal point for the Board. 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.

The Group 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. EnQuest has now moved to a 4 - 1 office to work from home ratio to enhance productivity and motivate staff. 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.

Potential impact

Medium (2022 Medium)

Likelihood

Medium (2022 Medium)

Change from last year

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

Risk appetite

Medium (2022 Medium)

PRODUCTION DETAILS

Average daily production on a net working interest basis	1 Jan 2023 to 31 Dec 2023	1 Jan 2022 to 31 Dec 2022
	(Boepd)	(Boepd)
UK Upstream
- Magnus	15,933	12,641
- Kraken	13,580	18,394
- Golden Eagle	4,199	6,323
- Other Upstream¹	2,663	3,443
Total UK	36,375	40,801
Total Malaysia	7,437	6,458
Total EnQuest	43,812	47,259

¹ Other Upstream: Scolty/Crathes, Greater Kittiwake Area and Alba

KEY PERFORMANCE INDICATORS

	2023	2022	2021
ESG metrics:
Group LTIF¹	0.52	0.57	0.21
Emissions (kilo-tonnes of CO₂ equivalent)	1,042.6	1,051.9	1,164.1
Business performance data:
Production (Boepd)	43,812	47,259	44,415
Unit opex (production and transportation costs) ($/Boe)²	21.9	22.7	20.5
Cash expenditures ($ million)	211.1	174.8	117.6
Capital²	152.2	115.8	51.8
Decommissioning	58.9	59.0	65.8
Reported data:
Cash generated from operations ($ million)	854.7	1,026.1	756.9
EnQuest net debt ($ million)²	480.9	717.1	1,222.0
Net 2P reserves (MMboe)	175	190	205

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 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP Measures' starting on page 65

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 reserves1, 2, 3
At 31 December 2022		160		30	190
Revisions of previous estimates	(4)		(0)
Transfers from contingent resources4	4		0
		0		0	0
Production:
Export meter	(13)		(3)
Volume adjustments5	0		-
		(13)		(3)	(16)
Total proven and probable reserves at 31 December 20236, 7		147		28	175
Contingent resources^1, 2, 8, 10
At 31 December 2022		312		81	393
Promoted to reserves9		(4)		0	(4)
Total contingent resources at 31 December 202310		308		81	389
Notes:

1 Opening reserves are quoted on a working interest 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 Transfers from 2C resources at Magnus

5 Correction of export to sales volumes

6 The above 2P reserves include volumes that will be consumed as fuel gas, including c.6.9 MMboe at Magnus, c.0.8 MMboe at Kraken, c.0.3 MMboe at Golden Eagle and c.0.1 MMboe at Scolty Crathes

7 The above proven and probable reserves on an entitlement basis are 165 MMboe (UKCS 147 MMboe and other regions 18 MMboe)

8 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

9 Magnus CoP extension

10 2C contingent resources at 31 December 2023 do not reflect the transfer of a 15.0% share in the Bressay licence to RockRose that completed in March 2023

11 Rounding may apply

Group Income Statement

For the year ended 31 December 2023

	Notes	2023			2022
	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)	1,458,956	28,463	1,487,419	1,839,147		14,475	1,853,622
Cost of sales	5(b)	(941,102)	(5,650)	(946,752)	(1,195,806)		(4,900)	(1,200,706)
Gross profit/(loss)		517,854	22,813	540,667	643,341		9,575	652,916
Net impairment (charge)/reversal to oil and gas assets	4,10	-	(117,396)	(117,396)	-		(81,049)	(81,049)
General and administration expenses	5(c)	(6,348)	-	(6,348)	(7,553)		-	(7,553)
Other income	5(d)	17,897	78,984	96,881	76,247		7,706	83,953
Other expenses	5(e)	(46,846)	(10,731)	(57,577)	(2,810)		(233,570)	(236,380)
Profit/(loss) from operations before tax and finance income/(costs)		482,557	(26,330)	456,227	709,225		(297,338)	411,887
Finance costs	6	(172,087)	(58,854)	(230,941)	(176,227)		(36,410)	(212,637)
Finance income	6	6,493	-	6,493	1,816		2,148	3,964
Profit/(loss) before tax		316,963	(85,184)	231,779	534,814		(331,600)	203,214
Income tax	7	(287,750)	25,138	(262,612)	(322,468)		78,020	(244,448)
Profit/(loss) for the year attributable to owners of the parent		29,213	(60,046)	(30,833)	212,346		(253,580)	(41,234)
Total comprehensive profit/(loss) for the year, attributable to owners of the parent				(30,833)				(41,234)

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

Earnings per share	8	$	$	$	$
Basic		0.016	(0.016)	0.114	(0.022)
Diluted		0.016	(0.016)	0.112	(0.022)

The attached notes 1 to 31 form part of these Group financial statements.

Group Balance Sheet

At 31 December 2023

	Notes	2023 $'000	2022 $'000
ASSETS
Non-current assets
Property, plant and equipment	10	2,296,740	2,476,975
Goodwill	11	134,400	134,400
Intangible assets	12	18,323	45,299
Deferred tax assets	7(c)	540,122	705,808
Other financial assets	19	36,282	6
		3,025,867	3,362,488
Current assets
Intangible assets	12	876	1,199
Inventories	13	84,797	76,418
Trade and other receivables	16	225,486	276,363
Current tax receivable		1,858	1,491
Cash and cash equivalents	14	313,572	301,611
Other financial assets	19	113,326	4,705
		739,915	661,787
TOTAL ASSETS		3,765,782	4,024,275
EQUITY AND LIABILITIES
Equity
Share capital and premium	20	393,831	392,196
Share-based payments reserve		13,195	11,510
Retained earnings	20	49,702	80,535
TOTAL EQUITY		456,728	484,241
Non-current liabilities
Borrowings	18	283,867	281,422
Bonds	18	463,945	452,386
Lease liabilities	24	288,892	362,966
Contingent consideration	22	461,271	513,677
Provisions	23	715,436	667,335
Deferred income	25	138,416	-
Trade and other payables	17	32,917	-
Deferred tax liabilities	7(c)	77,643	166,334
		2,462,387	2,444,120
Current liabilities
Borrowings	18	27,364	131,936
Bonds	18	-	134,544
Lease liabilities	24	133,282	119,100
Contingent consideration	22	46,525	123,198
Provisions	23	79,861	70,335
Trade and other payables	17	347,409	426,647
Other financial liabilities	19	26,679	50,966
Current tax payable		185,547	39,188
		846,667	1,095,914
TOTAL LIABILITIES		3,309,054	3,540,034
TOTAL EQUITY AND LIABILITIES		3,765,782	4,024,275

The attached notes 1 to 31 form part of these Group financial statements.

The financial statements were approved by the Board of Directors and authorised for issue on 27 March 2024 and signed on its behalf by:

Amjad Bseisu

Chief Executive Officer

Group Statement of Changes in Equity

For the year ended 31 December 2023

	Notes	Share capital and share premium $'000	Share-based payments reserve $'000	Retained earnings $'000	Total $'000
Balance at 1 January 2022		392,196	6,791	121,769	520,756
Loss for the year		-	-	(41,234)	(41,234)
Total comprehensive expense 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
Loss for the year		-	-	(30,833)	(30,833)
Total comprehensive expense for the year		-	-	(30,833)	(30,833)
Issue of shares to Employee Benefit Trust	20	1,635	(1,635)	-	-
Share-based payment	21	-	3,320	-	3,320
Balance at 31 December 2023		393,831	13,195	49,702	456,728

The attached notes 1 to 31 form part of these Group financial statements.

Group Statement of Cash Flows

For the year ended 31 December 2023

	Notes	2023 $'000	2022 $'000
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations	30	854,746	1,026,149
Cash received from insurance		5,190	15,015
Cash (paid)/received on purchase of financial instruments		(5,795)	(1,354)
Decommissioning spend		(58,911)	(58,964)
Income taxes paid		(40,986)	(49,293)
Net cash flows from/(used in) operating activities		754,244	931,553
INVESTING ACTIVITIES
Purchase of property, plant and equipment		(141,741)	(107,668)
Proceeds from farm-down	25	141,360	-
Vendor financing facility	25	(141,360)	-
Purchase of intangible oil and gas assets		(10,467)	(8,168)
Purchase of other intangible assets	12	(876)	(1,199)
Payment of Magnus contingent consideration - Profit share	22	(65,506)	(45,975)
Payment of Golden Eagle contingent consideration - Acquisition	22	(50,000)	-
Interest received		5,895	1,763
Net cash flows (used in)/from investing activities		(262,695)	(161,247)
FINANCING ACTIVITIES
Proceeds from loans and borrowings		190,657	87,215
Repayment of loans and borrowings		(427,736)	(567,020)
Payment of obligations under financing leases	24	(135,675)	(147,971)
Interest paid		(105,877)	(103,387)
Net cash flows (used in)/from financing activities		(478,631)	(731,163)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS		12,918	39,143
Net foreign exchange on cash and cash equivalents		(957)	(24,193)
Cash and cash equivalents at 1 January		301,611	286,661
CASH AND CASH EQUIVALENTS AT 31 DECEMBER		313,572	301,611
Reconciliation of cash and cash equivalents
Total cash at bank and in hand	14	313,028	293,866
Restricted cash	14	544	7,745
Cash and cash equivalents per balance sheet		313,572	301,611

The attached notes 1 to 31 form part of these Group financial statements.

Notes to the Group Financial Statements

For the year ended 31 December 2023

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. The address of the Company's registered office is shown on the inside back cover.

EnQuest PLC is the ultimate controlling party. 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 2023 were authorised for issue in accordance with a resolution of the Board of Directors on 27 March 2024.

A listing of the Group's companies is contained in note 29 to these Group financial statements.

2. Basis of preparation

The consolidated financial statements have been prepared in accordance with UK-adopted International Financial Reporting Standards ('IFRS') 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 2023.

The Group financial information has been prepared on a 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.

In recent years, given the prevailing macroeconomic and fiscal environment, the Group has prioritised deleverage - reducing gross debt (excluding leases) by c.$1.4 billion since 2017 to $794.5 million at 31 December 2023. During 2023, EnQuest net debt was reduced by $236.2 million (to $480.9 million) and the Group strengthened its net debt to adjusted EBITDA ratio to 0.6x, close to EnQuest's target of 0.5x. In this 12-month period, cash and available facilities increased by $149.9 million, to $498.8 million at 31 December 2023, and medium-term liquidity is secured, with all the Group's debt maturities now in 2027.

The Base Case has also been subjected to further testing through a scenario reflecting the impact of the following plausible downside risks (the 'Downside Case'):

· 10% discount to Base Case prices resulting in Downside Case prices of $72.0/bbl for 2024 and $67.5/bbl for 2025;

· Production risking of 5.0%; and

· 2.5% increase in operating, capital and decommissioning expenditure.

The Base Case and Downside case indicate 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.

New standards and interpretations

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

· Insurance contracts (IFRS 17)

· Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS Practice Statement 2)

· Definition of Accounting Estimates (Amendments to IAS 8)

· Deferred Tax related to Assets and Liabilities arising from a Single Transaction (Amendments to IAS 12)

· International Tax reform - Pillar Two Model Rules (Amendments to IAS 12)

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 10 and IAS 28 (amendments)	Sale or Contribution of Assets between an Investor and its Associate or Joint Venture
Amendments to IAS 1	Classification of Liabilities as Current or Non-current
Amendments to IAS 1	Non-current Liabilities with Covenants
Amendments to IAS 7 and IFRS 7	Supplier Finance Arrangements
Amendments to IFRS 16	Lease Liability in a Sale and Leaseback

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 the Company gains control until the date 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 2023, 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 the Group's 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 within the next financial year 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, cost profile changes including those related to emission reduction initiatives such as alternative fuel provision at Kraken, 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. Such estimates reflect management's best estimate of the related cash flows based on management's plans for the assets and their future development.

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, life of field production profiles, 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 2023 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 2023, the post-tax discount rate was estimated at 11.0% (2022: 11.0%) with the effect of the Group's reduced debt position offset by the impact of the general increase in interest rates.

Oil prices

The price assumptions used for FVLCD impairment testing were based on latest internal forecasts as at 31 December 2023, 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, the Audit Committee and the Board of Directors.

EnQuest revised its oil price assumptions for FVLCD impairment testing compared to those used in 2022. The Group's long-term price assumption was increased to better align with external forecasts. 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°C, 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 on Climate-related Financial Disclosures report. Discounts or premiums are applied to price assumptions based on the characteristics of the oil produced and the terms of the relevant sales contracts.

An inflation rate of 2% (2022: 2%) is applied from 2027 onwards to determine the price assumptions in nominal terms (see table below). The price assumptions used in 2022 were $84.0/bbl (2023), $80.0/bbl (2024), $75.0/bbl (2025) and $70.0/bbl real thereafter, inflated at 2.0% per annum from 2026.

	2024	2025	2026	2027>^*
Brent oil ($/bbl)	80	80	75	77

^· ^{Inflated at 2% from 2027}

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 28) 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, which it believes to be a reasonably possible change given the prevailing macroeconomic environment.

Price reductions of this magnitude in isolation could indicatively lead to a further reduction in the carrying amount of EnQuest's oil and gas properties by approximately $224.1 million, which is approximately 10% of the net book value of property, plant and equipment as at 31 December 2023.

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 of 11% 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 in 2023 would have been approximately $51.3 million higher. If the discount rate was one percentage point lower, the net impairment charge would have been approximately $56.0 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 (2022: $134.4 million), principally relating to the acquisition of Magnus oil field. 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 rising interest rate environment seen in 2023, the Group reassessed the fair value discount rate associated with the Magnus contingent consideration. This was estimated to be 11.3% as at the end of 2023 (2022: 10.0%), 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 rate used in discounting the cash flows is reviewed half-yearly. The nominal discount rate used to determine the balance sheet obligations at the end of 2023 was 3.5% (2022: 3.5%), reflecting the wider interest rate environment. 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 at 2.5% for 2024 and a long-term inflation rate of 2% thereafter (2022: 4% (2023), 3% (2024) and a long-term inflation rate of 2% thereafter) 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 one 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 $68.0 million (2022: $54.0 million). The pre-tax impact on the Group income statement would be a charge of approximately $67.1 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. Refer to note 12 for further details.

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 2023, 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 2023. The North Sea's activities include Upstream, Midstream, Decommissioning and Veri Energy. Veri Energy is not considered a separate operating segment as it does not yet earn revenues and does not yet have material capital and resources. Malaysia's activities include Upstream and Decommissioning. 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 paragraph 23.

Year ended 31 December 2023 $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(i), (ii)	Consolidated
Revenue and other operating income:
Revenue from contracts with customers	1,325,200	142,510	-	1,467,710	-	1,467,710
Other operating income/(expense)	2,229	-	281	2,510	17,199	19,709
Total revenue and other operating income/(expense)	1,327,429	142,510	281	1,470,220	17,199	1,487,419
Income/(expenses) line items:
Depreciation and depletion	(278,280)	(19,923)	(105)	(298,308)	-	(298,308)
Net impairment (charge)/reversal to oil and gas assets	(117,396)	-	-	(117,396)	-	(117,396)
Exploration write-off and impairments	-	(5,640)	-	(5,640)	-	(5,640)
Segment profit/(loss)(ii)	389,355	46,192	4,474	440,021	16,206	456,227
Other disclosures:
Capital expenditure(iii)	149,093	11,817	12	160,922	-	160,922

Year ended 31 December 2022 $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(i), (ii)	Consolidated
Revenue and other operating income:
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

(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

Reconciliation of profit/(loss):

	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000
Segment profit/(loss) before tax and finance income/(costs)	440,021	611,471
Finance costs	(230,941)	(212,637)
Finance income	6,493	3,964
Gain/(loss) on oil and foreign exchange derivatives(i)	16,206	(199,584)
Profit/(loss) before tax	231,779	203,214

(i) Includes $8.4 million realised losses on derivatives (2022: $209.2 million) and $24.6 million unrealised gains on derivatives (2022: $9.6 million)

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 $491.2 million and $201.3 million per each single customer (2022: two customers; $365.1 million and $321.7 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 2023 $'000	Fair value remeasurement⁽ⁱ⁾	Impairments and write-offs⁽ⁱⁱ⁾	Other⁽ⁱⁱⁱ⁾	Total
Revenue and other operating income	28,463	-	-	28,463
Cost of sales	(3,832)	-	(1,818)	(5,650)
Net impairment (charge)/reversal on oil and gas assets	-	(117,396)	-	(117,396)
Other income	69,665	-	9,319	78,984
Other expense	-	(5,640)	(5,091)	(10,731)
Finance costs	-	-	(58,854)	(58,854)
	94,296	(123,036)	(56,444)	(85,184)
Corporation tax on items above	(37,788)	181	21,790	(15,817)
UK Energy Profits Levy	(38,560)	22,518	56,997	40,955
	17,948	(100,337)	22,343	(60,046)

4. Remeasurements and exceptional items continued

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 expenses	(233,570)	-	-	(233,570)
Finance costs	-	-	(36,410)	(36,410)
Finance income	-	-	2,148	2,148
	(222,925)	(81,049)	(27,626)	(331,600)
Corporation tax on items above	89,599	32,420	7,817	129,836
Recognition of undiscounted deferred tax asset(iv)	-	127,024	-	127,024
UK Energy Profits Levy(v)	-	-	(178,840)	(178,840)
	(133,326)	78,395	(198,649)	(253,581)

(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 $24.6 million (2022: $9.6 million). Other income relates to the fair value remeasurement of contingent consideration relating to the acquisition of Magnus and associated infrastructure of $69.7 million (note 22) (2022: net other expense of $232.5 million)

(ii) Impairments and write-offs include a net impairment charge of tangible oil and gas assets and right-of-use assets totalling $117.4 million (note 10) (2022: charge of $81.0 million) and write-off of exploration costs in Malaysia of $5.6 million (2022: nil)

(iii) Other items are made up of the following: other costs of sales includes $1.8 million related to an increase in a provision for a dispute with a third-party contractor (2022: nil). Other net income primarily includes $4.1 million recognition of insurance income related to the PM8/Seligi riser incident (2022: $6.6 million) and $0.1 million movement in other provisions (2022: nil). Finance costs relates to the finance cost element of the 75% acquisition of Magnus and associated infrastructure of $58.9 million (note 22) (2022: $36.4 million). In 2022, finance income of $2.1 million 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 is due to the Group's higher oil price assumptions

(v) In 2022, UK Energy Profits Levy ('EPL') represented the charge on initial recognition. In 2023, the related assumptions were refined, resulting in a credit of $32.7 million in other items. The remaining EPL items relate to the EPL charges and credits on the items above

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 operating revenue 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 2023 $'000	Year ended 31 December 2022 $'000
Revenue from contracts with customers:
Revenue from crude oil sales	1,127,419	1,517,666
Revenue from gas and condensate sales(i)	338,973	514,206
Tariff revenue	1,318	920
Total revenue from contracts with customers	1,467,710	2,032,792
Realised gains/(losses) on oil derivative contracts (see note 19)	(11,264)	(203,741)
Other	2,510	10,096
Business performance revenue and other operating income	1,458,956	1,839,147
Unrealised gains/(losses) on oil derivative contracts(ii) (see note 19)	28,463	14,475
Total revenue and other operating income	1,487,419	1,853,622

(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 2023 $'000				Year ended 31 December 2022 $'000
	North Sea	Malaysia	Total	North Sea		Malaysia	Total
Revenue from contracts with customers:
Revenue from crude oil sales	987,610	139,809	1,127,419	1,360,228		157,438	1,517,666
Revenue from gas and condensate sales(i)	336,902	2,071	338,973	512,066		2,140	514,206
Tariff revenue	689	629	1,318	920		-	920
Total revenue from contracts with customers	1,325,201	142,509	1,467,710	1,873,214		159,578	2,032,792

(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 ('NRV'), 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 2023 $'000	Year ended 31 December 2022 $'000
Production costs	308,331	347,832
Tariff and transportation expenses	41,736	43,266
Realised (gain)/loss on derivative contracts related to operating costs (see note 19)	(2,839)	5,418
Change in lifting position	(2,669)	(18,790)
Crude oil inventory movement	(1,575)	3,222
Depletion of oil and gas assets(i)	292,199	327,027
Other cost of operations(ii)	305,919	487,831
Business performance cost of sales	941,102	1,195,806
Unrealised losses/(gains) on derivative contracts related to operating costs(iii) (see note 19)	3,832	4,900
Movement in contractor dispute provision (see note 23)	1,818	-
Total cost of sales	946,752	1,200,706

(i) Includes $28.6 million (2022: $38.7 million) Kraken FPSO right-of-use asset depreciation charge and $24.0 million (2022: $15.8 million) of other right-of-use assets depreciation charge

(ii) Includes $294.0 million (2022: $452.8 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 2023 $'000	Year ended 31 December 2022 $'000
Staff costs (see note 5(f))	77,517	75,266
Depreciation(i)	6,109	6,222
Other general and administration costs	25,490	21,740
Recharge of costs to operations and joint venture partners	(102,768)	(95,675)
Total general and administration expenses	6,348	7,553

(i) Includes $3.4 million (2022: $3.4 million) right-of-use assets depreciation charge on buildings

(d) Other income

	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000
Net foreign exchange gains	-	21,329
Change in decommissioning provisions (see note 23)	-	36,763
Change in Thistle decommissioning provisions (see note 23)	-	6,060
Rental income from office sublease	2,286	1,549
Other	15,611	10,546
Business performance other income	17,897	76,247
Fair value changes in contingent consideration (see note 22)	69,665	1,070
Other non-business performance (see note 4)	9,319	6,636
Total other income	96,881	83,953

(e) Other expenses

	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000
Net foreign exchange losses	11,659	-
Change in decommissioning provisions (see note 23)	31,159	-
Change in Thistle decommissioning provisions (see note 23)	1,605	-
Other	2,423	2,810
Business performance other expenses	46,846	2,810
Fair value changes in contingent consideration (see note 22)	-	233,570
Other non-business performance (see note 4)	10,731	-
Total other expenses	57,577	236,380

(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 2023 $'000	Year ended 31 December 2022 $'000
Wages and salaries	63,458	63,430
Social security costs	5,457	6,547
Defined contribution pension costs	5,038	4,968
Expense of share-based payments (see note 21)	3,320	4,719
Other staff costs	11,079	12,984
Total employee costs	88,352	92,648
Contractor costs	38,304	33,661
Total staff costs	126,656	126,309

General and administration staff costs (see note 5(c))	77,517	75,266
Non-general and administration costs	49,139	51,043
Total staff costs	126,656	126,309

The monthly average number of persons, excluding contractors, employed by the Group during the year was 697, with 343 in the general and administration staff costs and 354 directly attributable to assets (2022: 715 of which 335 in general and administration and 380 directly attributable to assets). Compensation of key management personnel is disclosed in note 26 and in the Directors' Remuneration Report.

(g) Auditor's remuneration

The following amounts for the year ended 31 December 2023 and for the comparative year ended 31 December 2022 were payable by the Group to Deloitte:

	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000
Fees payable to the Company's auditor for the audit of the parent company and Group financial statements	1,239	1,064
The audit of the Company's subsidiaries	177	274
Total audit	1,416	1,338
Audit-related assurance services(i)	314	649
Total audit and audit-related assurance services	1,730	1,987
Total auditor's remuneration	1,730	1,987

(i) Audit-related assurance services in both years include the review of the Group's interim results, G&A assurance review and the Bond refinancing activities

6. Finance costs/income

Accounting policy

Borrowing costs are recognised as interest payable within finance costs at amortised cost using the effective interest method.

	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000
Finance costs:
Loan interest payable	30,708	14,906
Bond interest payable	58,999	62,260
Unwinding of discount on decommissioning provisions (see note 23)	24,236	16,995
Unwinding of discount on other provisions (see note 23)	1,145	777
Finance charges payable under leases (see note 24)	43,801	39,172
Amortisation of finance fees on loans and bonds	7,899	35,287
Other financial expenses(i)	5,299	6,830
Business performance finance expenses	172,087	176,227
Unwinding of discount on Magnus-related contingent consideration (see note 22)	58,854	36,410
Total finance costs	230,941	212,637
Finance income:
Bank interest receivable	6,493	1,816
Business performance finance income	6,493	1,816
Other financial income (see note 4)	-	2,148
Total finance income	6,493	3,964

(i) Includes unwinding of discount on Golden Eagle contingent consideration of $1.7 million (2022: $3.2 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 a temporary difference arises from initial recognition of other assets or liabilities 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

The Energy (Oil & Gas) Profits Levy Act 2022 ('EPL') applies an additional tax on the profits earned by oil and gas companies from the production of oil and gas on the United Kingdom Continental Shelf until 31 March 2028 (see note 7(e) for extension to 31 March 2029). This 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 UK companies. Current and deferred tax is provided on the same basis as described above for income taxes.

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

	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000
Current UK income tax
Current income tax charge	-	-
Adjustments in respect of current income tax of previous years	(14)	(243)
Current overseas income tax
Current income tax charge	24,685	19,017
Adjustments in respect of current income tax of previous years	(2,567)	(6,551)
UK Energy Profits Levy
Current year charge	175,118	72,147
Adjustments in respect of current charge of previous years	(11,605)	-
Total current income tax	185,617	84,370
Deferred UK income tax
Relating to origination and reversal of temporary differences	160,712	1,784
Adjustments in respect of changes in tax rates	-	45
Adjustments in respect of deferred income tax of previous years	4,974	(4,668)
Deferred overseas income tax
Relating to origination and reversal of temporary differences	(3,761)	6,884
Adjustments in respect of deferred income tax of previous years	1,430	2,363
Deferred UK Energy Profits Levy
Relating to origination and reversal of temporary differences	(58,661)	153,670
Adjustments in respect of deferred charge of previous years	(27,699)	-
Total deferred income tax	76,995	160,078
Income tax expense reported in profit or loss	262,612	244,448

(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 2023 $'000	Year ended 31 December 2022 $'000
Profit/(loss) before tax	231,779	203,214
UK statutory tax rate applying to North Sea oil and gas activities of 40% (2022: 40%)	92,712	81,284
Supplementary corporation tax non-deductible expenditure	10,580	11,486
Non-deductible expenditure(i)	69,494	47,951
Petroleum revenue tax (net of income tax benefit)	(8,200)	-
Tax in respect of non-ring-fence trade	7,418	8,892
Deferred tax asset impairment in respect of non-ring-fence trade	11,696	8,563
Deferred tax asset recognition in respect of ring-fence trade	-	(127,022)
UK Energy Profits Levy(ii)	116,457	225,817
Adjustments in respect of prior years	(35,481)	(9,098)
Overseas tax rate differences	(1,114)	(1,264)
Share-based payments	(90)	(1,345)
Other differences	(860)	(816)
At the effective income tax rate of 113% (2022: 120%)	262,612	244,448

(i) Predominantly in relation to non-qualifying expenditure relating to the initial recognition exemption utilised under IAS 12 upon acquisition of Golden Eagle given that at the time of the transaction, it affected neither accounting profit nor taxable profit

(ii) Includes current EPL charge of $175.1 million (2022: $72.1 million charge) and deferred EPL credit of $58.7 million (2022: $153.7 million charge)

Deferred income tax relates to the following:

	Group balance sheet		Charge/(credit) for the year recognised in profit or loss
	2023 $'000	2022 $'000	2023 $'000	2022 $'000
Deferred tax liability
Accelerated capital allowances	877,800	963,816	(86,015)	195,185
	877,800	963,816
Deferred tax asset
Losses	(695,888)	(902,101)	206,213	114,996
Decommissioning liability	(265,800)	(238,624)	(27,176)	47,421
Other temporary differences	(378,592)	(362,565)	(16,027)	(197,524)
	(1,340,280)	(1,503,290)	76,995	160,078
Net deferred tax (assets)	(462,479)	(539,474)
Reflected in the balance sheet as follows:
Deferred tax assets	(540,122)	(705,808)
Deferred tax liabilities	77,643	166,334
Net deferred tax (assets)	(462,479)	(539,474)

Reconciliation of net deferred tax assets/(liabilities)

	2023 $'000	2022 $'000
At 1 January	539,474	699,552
Tax expense during the period recognised in profit or loss	(76,995)	(160,078)
At 31 December	462,479	539,474

(d) Tax losses

The Group's deferred tax assets at 31 December 2023 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. 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 $62.5 million while 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 $442.1 million (2022: $389.7 million) and ring-fence tax losses of $1,163.0 million (2022: $1,163.0 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 $8.5 million (2022: $10.7 million) remaining unrecognised.

The Group has unused Malaysian income tax losses of $14.3 million (2022: $14.3 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

Finance Act 2001 amended the mainstream corporation tax rate to 25% from 1 April 2023. The change had no impact in the current year as UK mainstream corporation tax losses are not recognised.

In the Autumn Statement on 22 November 2023, the UK Government confirmed that it will bring in legislation for the Energy Security Investment Mechanism and has agreed to index link the trigger floor price to the CPI from April 2024. The Government also announced that once the decarbonisation allowance of 80% against EPL is withdrawn in March 2028, it will replace this with a new allowance at the same effective rate against the permanent tax regime. In March 2024, the UK Government announced that the sunset clause for EPL would be extended by a year to 31 March 2029, the impact on the current year financial statements would be an increase in the tax charge and deferred tax for EPL by $44.6 million. The Group will continue to monitor developments and any potential related impacts.

The UK has introduced legislation implementing the Organisation for Economic Co-operation and Development's ('OECD') proposals for a global minimum corporation tax rate (Pillar Two) which is effective for periods beginning on or after 31 December 2023. This legislation will ensure that profits earned internationally are subject to a minimum tax rate of 15%. The Group has performed an assessment of the potential exposure to Pillar Two income taxes from 1 January 2024 and as the only material overseas jurisdiction in which the Group operates is Malaysia, which is subject to a tax rate of 38%, the Group does not expect a material exposure to Pillar Two income taxes in any jurisdictions. The Group has applied the mandatory exception to recognising and disclosing information about the deferred tax assets and liabilities related to Pillar Two income taxes in accordance with the amendments to IAS 12 published by the International Accounting Standards Board ('IASB') on 23 May 2023.

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
	2023 $'000	2022 $'000	2023 million	2022 million	2023 $	2022 $
Basic	(30,833)	(41,234)	1,871.9	1,855.0	(0.016)	(0.022)
Dilutive potential of Ordinary shares granted under share-based incentive schemes	-	-	4.9	39.2	-	-
Diluted(i)	(30,833)	(41,234)	1,876.8	1,894.2	(0.016)	(0.022)
Basic (excluding remeasurements and exceptional items)	29,213	212,346	1,871.9	1,855.0	0.016	0.114
Diluted (excluding remeasurements and exceptional items)(i)	29,213	212,346	1,876.8	1,894.2	0.016	0.112

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

9. Distributions paid and proposed

The Company paid no dividends during the year ended 31 December 2023 (2022: none). At 31 December 2023, there are no proposed dividends (2022: none). The Board of Directors of EnQuest PLC are proposing making a $15.0 million share buy back, to be executed during 2024. The distribution will be below the limit granted at the 2023 Annual General Meeting allowing the Company to purchase up to 10% of its issued Ordinary share capital in the market.

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 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 1 January 2023	9,037,851	67,321	876,859	9,982,031
Additions	120,820	1,257	28,378	150,455
Change in decommissioning provision (note 23)	53,333	-	-	53,333
Disposal	-	-	(243)	(243)
Reclassification from intangible assets (note 12)	31,803	-	-	31,803
At 31 December 2023	9,243,807	68,578	904,994	10,217,379
Accumulated depreciation, depletion and impairment:
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 1 January 2023	7,000,950	56,625	447,481	7,505,056
Charge for the year	239,640	2,689	55,979	298,308
Net impairment charge/(reversal) for the year	123,473	-	(6,077)	117,396
Disposal	-	-	(121)	(121)
At 31 December 2023	7,364,063	59,314	497,262	7,920,639
Net carrying amount:
At 31 December 2023	1,879,744	9,264	407,732	2,296,740
At 31 December 2022	2,036,901	10,696	429,378	2,476,975
At 1 January 2022	2,347,049	11,556	463,393	2,821,998

The amount of borrowing costs capitalised during the year ended 31 December 2023 was nil (2022: nil), reflecting the short-term nature of the Group's capital expenditure programmes.

Impairments

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

	Impairment reversal/(charge)		Recoverable amount(i)
	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000	31 December 2023 $'000	31 December 2022 $'000
North Sea	(117,396)	(81,049)	1,323,009	1,448,391
Net pre-tax impairment reversal/(charge)	(117,396)	(81,049)

(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, along with sensitivity analysis, see Use of judgements, estimates and assumptions: recoverability of asset carrying values within note 2.

The 2023 net impairment charge of $117.4 million relates to producing assets in the UK North Sea. Impairment charges/reversals were primarily driven by changes in production and cost profile updates on non-operated assets, partially offset by higher forecast oil prices. The 2022 net impairment charge was 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.

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:

	2023 $'000	2022 $'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, relates to the 75% acquisition of the Magnus oil field and associated interests. The remaining balance relates to the acquisition of the GKA and Scolty Crathes fields.

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 2023 (2022: 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 assumptions, 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 charge (2022: 10% reduction would not result in an impairment charge). A 20% reduction in oil price would fully impair goodwill (2022: 25%).

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 2023, there was no impairment of historical exploration and appraisal expenditures (2022: nil), although $31.8 million of intangible assets associated with the Kraken field were transferred to property, plant and equipment, reflecting updated drilling plans following assessment of previous seismic survey information. During 2023, Malaysia drilled an exploration well on the PM409 licence. The results indicated that there were no commercial prospects and as a result costs of $5.6 million have been written off through the income statement.

Other intangibles

UK emissions allowances ('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 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 1 January 2023	154,937	1,199	156,136
Additions	10,467	876	11,343
Write-off of relinquished licences previously impaired	(485)	-	(485)
Write-off of unsuccessful exploration expenditure	(5,640)	-	(5,640)
Transfer to property, plant and equipment (note 10)	(31,803)	-	(31,803)
Disposal	-	(1,199)	(1,199)
At 31 December 2023	127,476	876	128,352
Accumulated impairment:
At 1 January 2022	(134,766)	-	(134,766)
Write-off of relinquished licences previously impaired	25,128	-	25,128
At 1 January 2023	(109,638)	-	(109,638)
Write-off of relinquished licences previously impaired	485	-	485
At 31 December 2023	(109,153)	-	(109,153)
Net carrying amount:
At 31 December 2023	18,323	876	19,199
At 31 December 2022	45,299	1,199	46,498
At 1 January 2022	37,615	10,052	47,667

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.

	2023 $'000	2022 $'000
Hydrocarbon inventories	21,189	19,613
Well supplies	63,608	56,805
	84,797	76,418

During 2023, a net gain of $2.2 million was recognised within cost of sales in the Group income statement relating to inventory (2022: net loss of $4.0 million). The $8.4 million increase in well supplies was primarily driven by increased drilling activities.

The inventory valuation at 31 December 2023 is stated net of a provision of $36.3 million (2022: $38.9 million) to write-down well supplies to their estimated net realisable value.

Inventory with a net book value of $2.9 million was sold as part of the Bressay farm-down (note 25).

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.

	2023 $'000	2022 $'000
Available cash	313,028	293,866
Restricted cash	544	7,745
Cash and cash equivalents	313,572	301,611

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 2023 is restricted cash of $0.5 million placed on deposit in relation to bank guarantees for the Group's Malaysian assets (31 December 2022: $7.7 million).

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 loss allowance 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 FVPL.

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 FVPL

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 28. 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.

Financial assets with cash flows that are not solely payments of principal and interest are classified and measured at FVPL, 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 2023	Notes	Total $'000	Amortised cost $'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	19(a)	4,499	-	-	4,499	-
Other financial assets measured at FVPL
Quoted equity shares		6	-	6	-	-
Total financial assets measured at fair value		4,505	-	6	4,499	-
Financial assets measured at amortised cost:
Vendor financing facility	19(f)	145,103	145,103	-	-	-
Total financial assets measured at amortised cost⁽ⁱⁱ⁾		145,103	145,103	-	-	-
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Oil commodity derivative contracts	19(a)	18,418	-	-	18,418	-
Forward UKA contracts	19(a)	8,261	-	-	8,261	-
Other financial liabilities measured at FVPL
Contingent consideration	22	507,796	-	-	-	507,796
Total liabilities measured at fair value		534,475	-	-	26,679	507,796
Liabilities measured at amortised cost
Interest-bearing loans and borrowings⁽ⁱⁱ⁾	18(a)	319,784	319,784	-	-	-
Retail bond 9.00%	18(b)	158,683	-	158,683	-	-
High yield bond 11.625%	18(b)	292,419	-	292,419	-	-
Total liabilities measured at amortised cost⁽ⁱ⁾		770,886	319,784	451,102	-	-

⁽ⁱ⁾ Excludes related fees

⁽ⁱⁱ⁾ Amortised cost is a reasonable approximation of the fair value

31 December 2022	Notes	Total $'000	Amortised cost $'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(a)	46,537	-	-	46,537	-
Forward UKA contracts	19(a)	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:
Interest-bearing loans and borrowings⁽ⁱⁱ⁾	18(a)	417,967	417,967	-	-	-
Retail bond 7.00%	18(b)	133,535	-	133,535	-	-
Retail bond 9.00%	18(b)	153,754	-	153,754	-	-
High yield bond 11.625%	18(b)	297,528	-	297,528	-	-
Total liabilities measured at amortised cost⁽ⁱ⁾		1,002,784	417,967	584,817	-	-

⁽ⁱ⁾ Excludes related fees

⁽ⁱⁱ⁾ Amortised cost is a reasonable approximation of the fair value

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. prices) or indirectly (i.e. derived from prices) observable; and

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, details of which and a reconciliation of movements are disclosed in note 22. There have been no transfers between Level 1 and Level 2 during the period (2022: no transfers).

For the financial assets and 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, while interest-bearing loans and borrowings and the vendor financing facility were calculated at amortised cost using the effective interest method to capture the present value (Level 3). A reconciliation of movements is disclosed in note 30.

16. Trade and other receivables

	2023 $'000	2022 $'000
Current
Trade receivables	31,905	69,508
Joint venture receivables	79,036	95,854
Under-lift position	22,309	26,474
VAT receivable	3,314	-
Other receivables	3,715	4,141
Prepayments	2,781	1,271
Accrued income	82,426	79,115
	225,486	276,363

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 2023 or 2022.

17. Trade and other payables

	2023 $'000	2022 $'000
Current
Trade payables	75,981	82,897
Accrued expenses	228,664	300,317
Over-lift position	18,824	25,658
Joint venture creditors	20,262	11,957
VAT payable	-	5,282
Other payables	3,678	536
Total Current	347,409	426,647
Non-current
Joint venture creditors	32,917	-
Total Non-current	32,917	-

The carrying value of the Group's current 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.

The carrying value of the Group's non-current trade and other payables as stated above is considered to be a reasonable approximation to their fair value as this is a specific bi-lateral agreement between counterparties with the liability extinguished in full over time in accordance with the agreed schedule.

18. Loans and borrowings

	2023 $'000	2022 $'000
Borrowings	311,231	413,358
Bonds	463,945	586,930
	775,176	1,000,288

(a) Borrowings

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

	2023			2022
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
RBL facility	140,000	(4,920)	135,080	400,000	(4,609)	395,391
Term Loan facility	150,000	(3,633)	146,367	-	-	-
SVT working capital facility	29,784	-	29,784	12,275	-	12,275
Vendor loan facility	-	-	-	5,692	-	5,692
Total borrowings	319,784	(8,553)	311,231	417,967	(4,609)	413,358
Due within one year			27,364			131,936
Due after more than one year			283,867			281,422
Total borrowings			311,231			413,358

See liquidity risk - note 28 for the timing of cash outflows relating to loans and borrowings.

Reserve Based Lending facility ('RBL')

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 accrues at 4.00% plus a combination of an agreed credit adjustment spread and Secured Overnight Financing Rate ('SOFR').

As at 31 December 2023, the carrying value of the facility was $135.1 million (2022: $395.4 million), comprising the principal of $140.0 million out of accessible commitments of $309.0 million (2022: $400.0 million out of commitments of $500.0 million) and unamortised fees of $4.9 million (2022: $4.6 million).

At 31 December 2023, $166.2 million (2022: $47.3 million) remained available for drawdown under the RBL. By the end of February 2024, the Group had fully repaid the outstanding $140.0 million of its drawn Reserve Based Lending Facility.

At 31 December 2023, the Letter of Credit utilisation was $43.5 million (2022: $52.7 million).

Term Loan facility

In August 2023, the Group agreed a second lien US Dollar Term Loan facility of $150.0 million. This facility, which was drawn down in full in September 2023, matures in July 2027 and incurs interest at SOFR +7.90%. As at 31 December 2023, the carrying amount of the facility was $146.4 million (2022: nil), comprising the principal of $150.0 million and unamortised fees of $3.6 million. See note 27.

SVT working capital facility

EnQuest has extended 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 until April 2024. Agreements to transfer the facility to a replacement bank are expected to be executed in April 2024. The facility is guaranteed by BP EOC Limited until the earlier of: a) 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 June 2023, the Group agreed an amended and restated facility with a third-party vendor providing capacity for refinancing the payment of existing invoices up to an amount of £15.0 million, with interest payable monthly at a rate of 9.00% per annum. At 31 December 2023, nil was drawn down on the facility and so this facility expired on 1 January 2024 in accordance with the terms of the 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, £4.7 million was drawn down. This amount was fully repaid in May 2023. Interest was payable monthly at a rate of 8.00% per annum.

(b) Bonds

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

	2023			2022
	Principal $'000	Fees and discount $'000	Total $'000	Principal $'000	Fees and discount $'000	Total $'000
High yield bond 11.625%	305,000	(10,724)	294,276	305,000	(13,815)	291,185
Retail bond 7.00%	-	-	-	134,544	-	134,544
Retail bond 9.00%	169,669	-	169,669	161,201	-	161,201
Total	474,669	(10,724)	463,945	600,745	(13,815)	586,930
Due within one year			-			134,544
Due after more than one year			463,945			452,386
Total			463,945			586,930

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 2023 is $294.3 million (2022: $291.2 million). This includes bond principal of $305.0 million (2022: $305.0 million) less the unamortised original issue discount ('OID') of $3.3 million (2022: $4.2 million) and unamortised fees of $7.4 million (2022: $9.6 million). The high yield bond does not include accrued interest of $5.8 million (2022: $6.5 million), which is reported within trade and other payables. The fair value of the high yield bond is disclosed in note 15.

Retail bond 7.00%

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 an outstanding principal of £111.3 million. On 13 October 2023, the outstanding principal of £111.3 million was repaid in full.

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 2023 is $169.7 million (2022: $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 $2.7 million (2022: $2.6 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

	2023		2022
	Assets $'000	Liabilities $'000	Assets $'000	Liabilities $'000
Fair value through profit or loss:
Derivative commodity contracts	4,499	18,418	4,705	46,537
Derivative UKA contracts	-	8,261	-	4,429
Amortised cost:
Other receivables (Vendor financing facility) (notes 19(f), 25⁽ⁱ⁾ )	108,827	-	-	-
Total current	113,326	26,679	4,705	50,966
Fair value through profit or loss:
Quoted equity shares	6	-	6	-
Amortised cost:
Other receivables (Vendor financing facility) (notes 19(f), 25)	36,276	-	-	-
Total non-current	36,282	-	6	-

Total other financial assets and liabilities	149,608	26,679	4,711	50,966

⁽ⁱ⁾ Repayment of $108.8 million was received in the first quarter of 2024 in accordance with the agreed payment schedule between EnQuest and RockRose

(b) Income statement impact

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

Year ended 31 December 2023	Revenue and other operating income		Cost of sales
Year ended 31 December 2023	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	(21,463)	19,148	-	-
Commodity swaps	12,474	9,315	-	-
Commodity futures	(2,275)	-	-	-
Foreign exchange contracts	-	-	5,695	-
UKA contracts	-	-	(2,856)	(3,832)
	(11,264)	28,463	2,839	(3,832)

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)

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 2023, gains totalling $17.2 million (2022: losses of $189.3 million) were recognised in respect of commodity contracts designated as FVPL. This included losses totalling $11.3 million (2022: losses of $203.7 million) realised on contracts that matured during the year, and mark-to-market unrealised gains totalling $28.5 million (2022: gains of $14.5 million).

The mark-to-market value of the Group's open commodity contracts as at 31 December 2023 was a net liability of $13.9 million (2022: net liability of $41.8 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 2023, gains totalling $5.7 million (2022: losses of $5.4 million) were recognised in the Group income statement. This included realised gains totalling $5.7 million (2022: losses of $5.2 million) on contracts that matured in the year.

The mark-to-market value of the Group's open contracts as at 31 December 2023 was nil (2022: nil).

(e) UK emissions allowance forward contracts

The Group enters into forward contracts for the purchase of UKAs to manage its exposure to carbon emission credit prices.

The mark-to-market value of the Group's open contracts as at 31 December 2023 was $8.3 million (2022: $4.4 million).

(f) Other receivables

	Other receivables $'000	Equity shares $'000	Total $'000
At 1 January 2022 and 2023	-	6	6
Additions⁽ⁱ⁾	145,103	-	145,103
At 31 December 2023	145,103	6	145,109
Current			108,827
Non-current			36,282
			145,109

⁽ⁱ⁾Additions relate to a vendor financing facility entered into with RockRose Energy Limited on 29 December 2023 following the farm-down of a 15.0% share in the EnQuest Producer FPSO and capital items associated with the Bressay development. $108.8 million was repaid in the first quarter of 2024 with the remainder of $36.3 million repayable through future net cash flows from the Bressay field. Interest on the outstanding amount accrues at 2.5% plus the Bank of England's Base Rate

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 ('EBT') 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	Share capital $'000	Share premium $'000	Total $'000
At 1 January 2023	1,885,924,339	131,650	260,546	392,196
Issue of new shares to EBT	26,379,774	1,635	-	1,635
At 31 December 2023	1,912,304,113	133,285	260,546	393,831

At 31 December 2023, there were 8,449,793 shares held by the Employee Benefit Trust (2022: 21,663,181). The movement in the year was shares used to satisfy awards made under the Company's share-based incentive schemes offset by a subscription for additional Ordinary shares.

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.

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:

	2023 $'000	2022 $'000
Performance Share Plan	2,120	3,264
Other performance share plans	231	261
Sharesave Plan	969	1,194
	3,320	4,719

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	2023 Number	2022 Number
Outstanding at 1 January	102,271,264	125,493,995
Granted during the year	33,940,859	17,368,011
Exercised during the year	(19,459,260)	(15,712,039)
Forfeited during the year	(29,385,408)	(24,878,703)
Outstanding at 31 December	87,367,455	102,271,264
Exercisable at 31 December	17,944,371	10,490,719

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.

Share options	2023	2022
Share options	Number	Weighted average exercise price $	Number	Weighted average exercise price $
Outstanding at 1 January	33,308,249	0.14	37,518,927	0.14
Granted during the year	10,268,853	0.14	1,292,788	0.32
Exercised during the year	(19,977,354)	0.13	(2,150,313)	0.17
Forfeited during the year	(4,941,604)	0.17	(3,353,153)	0.14
Outstanding at 31 December	18,658,144	0.16	33,308,249	0.14
Exercisable at 31 December	6,553,159	0.13	445,318	0.17

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 2022	566,685	21,853	48,337	636,875
Change in fair value (see note 5(d))	(69,840)	175	-	(69,665)
Unwinding of discount (see note 6)	56,668	2,186	1,663	60,517
Utilisation	(65,506)	(4,425)	(50,000)	(119,931)
At 31 December 2023	488,007	19,789	-	507,796
Classified as:
Current	43,073	3,452	-	46,525
Non-current	444,934	16,337	-	461,271
	488,007	19,789	-	507,796

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 profit share arrangement with bp 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. This contingent consideration is a financial liability classified as measured at FVPL. 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 2023, which resulted in a decrease in fair value of $69.8 million (2022: increase of $233.6 million). The decrease in fair value in 2023 reflects a 1.3% increase in the discount rate to 11.3% (2022: 10.0%) and changes in the asset cost profile, partially offset by the Group's increased oil price assumptions. The increase in 2022 reflected the Group's higher long-term oil price assumptions and changes in asset profiles and cost assumptions. The fair value accounting effect and finance costs of $56.7 million (2022: $34.5 million) on the contingent consideration were recognised through remeasurements and exceptional items in the Group income statement. At 31 December 2023, the contingent profit-sharing arrangement cap of $1.0 billion was forecast to be met in the present value calculations (31 December 2022: cap was forecast to be met). Within the statement of cash flows, the profit share element of the repayment, $65.5 million (2022: $46.0 million) is disclosed separately under investing activities. At 31 December 2023, the contingent consideration for Magnus was $488.0 million (31 December 2022: $566.7 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 reported contingent consideration by $19.9 million. A 1.0% increase would decrease reported contingent consideration by $18.6 million. As the profit-sharing cap of $1.0 billion is forecast to be met 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 $83.3 million to the contingent consideration (2022: reduction of $73.6 million).

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 2023, the maturity analysis of the contingent consideration is disclosed in Risk management and financial instruments: liquidity risk (note 28).

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 2023, the amount due to bp calculated on an after-tax basis by reference to 30% of bp's decommissioning costs on Magnus was $19.8 million (2022: $21.9 million). Any reasonably possible change in assumptions would not have a material impact on the provision.

Golden Eagle contingent consideration

Part of the Golden Eagle acquisition consideration included an amount that was contingent on the average oil price between July 2021 and June 2023. Over the period July 2021 to June 2023, the average oil price was $89.6/bbl. As such, at 30 June 2023, the contingent consideration was valued at $50.0 million with settlement of this liability completing in July 2023 (2022: liability of $48.3 million).

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 2022	691,584	32,720	13,366	737,670
Additions during the year(i)	6,245	-	7,017	13,262
Changes in estimates(i)	78,247	1,605	(5,192)	74,660
Unwinding of discount	24,236	1,145	-	25,381
Utilisation	(44,550)	(10,160)	(797)	(55,507)
Foreign exchange	-	45	(214)	(169)
At 31 December 2023	755,762	25,355	14,180	795,297
Classified as:
Current	55,924	9,757	14,180	79,861
Non-current	699,838	15,598	-	715,436
	755,762	25,355	14,180	795,297

(i) Includes $31.2 million relating to assets in decommissioning disclosed in note 5(e) and $53.3 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 primarily 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 the net effect of $61.0 million increase in the underlying cost estimates and $35.0 million foreign exchange impact due to the strengthening Sterling to US Dollar exchange rates. At 31 December 2023, an estimated $175.7 million is expected to be utilised between one and five years (2022: $407.0 million), $355.6 million within six to ten years (2022: $67.6 million), and the remainder in later periods. For sensitivity analysis see Use of judgements, estimates and assumptions within note 2.

The Group enters into surety bonds principally to provide security for its decommissioning obligations. The surety bond facilities, which expired in December 2022, were renewed for 12 months, subject to ongoing compliance with the terms of the Group's borrowings. At 31 December 2023, the Group held surety bonds totalling $250.4 million (2022: $227.6 million).

Thistle decommissioning provision

In 2018, EnQuest exercised 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 the Thistle and Deveron fields, with the liability recognised within provisions. At 31 December 2023, the amount due to bp by reference to 7.5% of bp's decommissioning costs on Thistle and Deveron was $25.4 million (2022: $32.7 million), with the reduction mainly reflecting the utilisation in the period. Change in estimates of $1.6 million are included within other expense (2022: $6.1 million other income) and unwinding of discount of $1.1 million is included within finance income (2022: $0.8 million).

Other provisions

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 2023, the provision was increased to $9.1 million (31 December 2022: $7.5 million) reflecting legal costs and interest charges. The Group expects the dispute to be settled in 2024.

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 (see note 10).

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 2021	463,393	570,781
Additions in the period	28,394	28,130
Depreciation expense	(57,864)	-
Impairment charge	(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
Additions in the period (see note 10)	28,378	28,378
Depreciation expense (see note 10)	(55,979)	-
Impairment reversal (see note 10)	6,077	-
Disposal	(122)	-
Interest expense	-	43,801
Payments	-	(135,675)
Foreign exchange movements	-	3,604
As at 31 December 2023	407,732	422,174
Current		133,282
Non-current		288,892
		422,174

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 28.

Amounts recognised in profit or loss

	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000
Depreciation expense of right-of-use assets	55,979	57,864
Interest expense on lease liabilities	43,801	39,172
Rent expense - short-term leases	5,153	7,116
Rent expense - leases of low-value assets	113	50
Total amounts recognised in profit or loss	105,046	104,202

Amounts recognised in statement of cash flows

Year ended 31 December 2023

$'000

Year ended 31 December 2022

$'000

Total cash outflow for leases

135,675

147,971

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 2023 was $2.3 million (2022: $1.5 million).

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

	2023 $'000	2022 $'000
Less than one year	2,682	2,313
One to two years	2,011	2,542
Two to three years	872	1,905
Three to four years	873	822
Four to five years	889	824
More than five years	2,790	3,710
Total undiscounted lease payments	10,117	12,116

25. Deferred income

Accounting policy

Income is not recognised in the income statement until it is highly probable that the conditions attached to the income will be met.

Year ended 31 December 2023

$'000

Year ended 31 December 2022

$'000

Deferred income

138,416

In December 2023 a farm-down of an equity interest in the EnQuest Producer FPSO and certain capital spares related to the Bressay development was completed and cash received of $141.3 million. The same amount was lent back to the acquirer in December 2023 as vendor financing (see note 19(f)). Proceeds from the transaction are reported within deferred income, as these are contingent upon the Bressay development project achieving regulatory approval. Both parties are committed to delivering the development, however should the project not achieve regulatory approval there remains the option to deploy the assets on an alternative project.

26. Commitments and contingencies

Capital commitments

At 31 December 2023, the Group had commitments for future capital expenditure amounting to $43.8 million (2022: $9.5 million). The key components of this relate to drilling commitments for the Kraken and Golden Eagle fields and commitments for the new stabilisation facility at Sullom Voe Terminal. Where the commitment relates to a joint venture, the amount represents the Group's net share of the commitment. Where the Group is not the operator of the joint venture then the amounts are based on the Group's net share of committed future work programmes.

Other commitments

In the normal course of business, the Group will obtain surety bonds, Letters of Credit and guarantees. At 31 December 2023, the Group held surety bonds totalling $250.4 million (2022: $227.6 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, 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.

A contingent payment of $15.0 million to Equinor is due upon regulatory approval of a Bressay field development plan.

27. 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 29 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 2023 (2022: none).

Within the $150.0 million Term Loan, Double A Limited, a company beneficially owned by the extended family of Amjad Bseisu, lent $9.0 million on the same terms and conditions as all other lending parties. This is considered a smaller related party transaction under Listing Rule 11.1.10.

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.

	2023 $'000	2022 $'000
Short-term employee benefits	5,360	6,195
Share-based payments	144	3,049
Post-employment pension benefits	241	164
Termination payments	367	228
	6,112	9,636

28. 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 2023 and 2022, 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 2023 are disclosed in note 19. As of 31 December 2023, the Group held financial instruments (options and swaps) related to crude oil that covered 5.2 MMbbls of 2024 production and 1.6 MMbbls of 2025 production. The instruments have an effective average floor price of around $60/bbl in both 2024 and 2025. 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 2023.

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 2023	(4,000)	7,400
31 December 2022	(25,321)	19,922

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 9.00% 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 22% (2022: 26%) of the Group's sales and 95% (2022: 85%) 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 2023

GBP

$'000

MYR

$'000

Other

$'000

Total

$'000

Total financial assets

241,844

42,233

954

285,031

Total financial liabilities

618,235

9,801

1,295

629,331

Year ended 31 December 2022

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

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 2023	(34,908)	34,908
31 December 2022	(50,615)	50,615

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 2023, there were no trade receivables past due but not impaired (2022: nil) and no joint venture receivables past due (2022: $0.1 million) but not impaired. Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary. Any impact from ECL is disclosed in note 16.

Ageing of past due but not impaired receivables	2023 $'000	2022 $'000
Less than 30 days	-	-
30-60 days	-	-
60-90 days	-	-
90-120 days	-	-
120+ days	-	123
	-	123

At 31 December 2023, the Group had one customer accounting for 58% of outstanding trade receivables (2022: two customers, 79%) and no joint venture partner accounting for over 10% of outstanding joint venture receivables (2022: one joint venture partner, 25%).

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 2023, $166.2 million (2022: $47.3 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 and Term Loan facilities, are unsecured.

Year ended 31 December 2023	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	-	64,518	131,081	221,311	-	416,910
Bonds	-	50,749	50,749	576,415	-	677,913
Contingent consideration	-	46,555	95,335	289,823	393,187	824,900
Obligations under finance leases	-	160,341	70,062	229,310	36,322	496,035
Trade and other payables	-	347,408	13,167	19,750	-	380,325
	-	669,571	360,394	1,336,609	429,509	2,796,083

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	-	194,991	49,919	615,449	-	860,359
Contingent consideration	-	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

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 2023	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	414	3,111	17,264	1,000	-	21,789
Other derivative contracts	-	8,261	-	-	-	8,261
	414	11,372	17,264	1,000	-	30,050

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

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 shareholder distributions are 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 15).

	2023 $'000	2022 $'000
Loans, borrowings and bond(i) (A) (see note 18)	794,453	1,018,712
Cash and short-term deposits (see note 14)	(313,572)	(301,611)
EnQuest net debt (B) (ii)	480,881	717,101
Equity attributable to EnQuest PLC shareholders (C)	456,728	484,241
Profit/(loss) for the year attributable to EnQuest PLC shareholders (D)	(30,833)	(41,234)
Profit/(loss) for the year attributable to EnQuest PLC shareholders excluding remeasurements and exceptionals (E)	29,213	212,346
Adjusted EBITDA (F) (ii)	824,666	979,084
Gross gearing ratio (A/C)	1.7	2.1
Net gearing ratio (B/C)	1.1	1.5
EnQuest net debt/adjusted EBITDA (B/F) (ii)	0.6	0.7
Shareholders' return on investment (D/C)	N/A	N/A
Shareholders' return on investment excluding exceptionals (E/C)	6%	44%

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

(ii) See Glossary - non GAAP Measures on pages 65 to 68

29. Subsidiaries

At 31 December 2023, EnQuest PLC had investments in the following subsidiaries:

Name of company	Principal activity	Country of incorporation	Proportion of nominal value of issued ordinary 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%
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) Limited1	Construction, ownership and operation of an oil pipeline	Scotland	100%
EnQuest Global Services Limited(i)2	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)3	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%
Veri Energy (CCS) Limited(i)	Assessment and development of new energy and decarbonisation opportunities	England	100%
Veri Energy (Hydrogen) Limited⁽ⁱ⁾	Assessment and development of new energy and decarbonisation opportunities	England	100%
Veri Energy Holdings Limited	Intermediate holding company	England	100%
Veri Energy Limited(i)	Assessment and development of new energy and decarbonisation opportunities	England	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 Annan House, Palmerston Road, Aberdeen, Scotland, AB11 5QP, United Kingdom

2 Ground Floor, Colomberie House, St Helier, JE4 0RX,^, Jersey

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

30. Cash flow information

Cash generated from operations

	Notes	Year ended 31 December 2023 $'000	Year ended 31 December 2022 $'000
Profit/(loss) before tax		231,779	203,214
Depreciation	5(c)	6,109	6,222
Depletion	5(b)	292,199	327,026
Exploration and appraisal expense		5,640	-
Net impairment charge to oil and gas assets	4	117,396	81,049
Net (write back)/disposal of inventory		(622)	762
Share-based payment charge	5(f)	3,320	4,719
Change in Magnus related contingent consideration	22	(10,811)	268,910
Change in provisions	23	59,970	(25,001)
Other non-cash income	5(d)	(4,058)	(6,636)
Change in Golden Eagle related contingent consideration	22	1,663	3,162
Option premium recognition		-	1,331
Unrealised (gain)/loss on commodity financial instruments	5(a)	(28,463)	(14,475)
Unrealised loss/(gain) on other financial instruments	5(b)	3,832	4,900
Unrealised exchange loss/(gain)		12,401	(13,588)
Net finance expense		140,213	154,492
Operating cashflow before working capital changes		830,568	996,087
Decrease in trade and other receivables		51,724	12,714
Increase in inventories		(9,518)	(5,388)
(Decrease)/increase in trade and other payables		(18,028)	22,736
Cash generated from operations		854,746	1,026,149

Changes in liabilities arising from financing activities

	Loans and borrowings $'000	Bonds $'000	Lease liabilities $'000	Total $'000
At 1 January 2022	(402,065)	(1,109,920)	(570,781)	(2,082,766)
Cash movements:
Repayments of loans and borrowings	415,000	827,166	-	1,242,166
Proceeds from loans and borrowings	(409,180)	(376,163)	-	(785,343)
Payment 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	32,036	6,614	39,727
At 31 December 2022	(413,528)	(597,283)	(482,066)	(1,492,877)
Cash movements:
Repayments of loans and borrowings	265,809	138,052	-	403,861
Proceeds from loans and borrowings	(166,782)	-	-	(166,782)
Payment of lease liabilities	-	-	135,675	135,675
Cash interest paid in year	36,285	62,130	-	98,415
Non-cash movements:
Additions	-	-	(28,377)	(28,377)
Interest/finance charge payable	(30,708)	(58,999)	(43,801)	(133,508)
Fee amortisation	(1,476)	(3,091)	-	(4,567)
Foreign exchange and other non-cash movements	(810)	(11,828)	(3,605)	(16,243)
At 31 December 2023	(311,210)	(471,019)	(422,174)	(1,204,403)

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	(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)
Principal	(319,784)	(474,669)	(422,174)	(1,216,627)
Unamortised fees	8,553	10,724	-	19,277
Accrued interest (note 17)	21	(7,074)	-	(7,053)
At 31 December 2023	(311,210)	(471,019)	(422,174)	(1,204,403)

31. Subsequent events

In March 2024, the UK Government announced that the sunset clause for EPL would be extended by a year to 31 March 2029, although no date has yet been set for when this will be legislated. The Group estimates the impact of this one year extension to be an additional deferred tax liability of approximately $44.6 million, with a reduction in the carrying value of the Group's assets of approximately $22.3 million.

In February 2024, the regulator approved the 15.0% disposal of a share in the Bressay licence to RockRose.

By the end of February 2024, the Group had fully repaid the outstanding $140.0 million of its drawn Reserve Based Lending Facility.

The Board of Directors of EnQuest PLC are proposing making a $15.0 million share buy back, to be executed during 2024. The distribution will be below the limit granted at the 2023 Annual General Meeting allowing the Company to purchase up to 10% of its issued Ordinary share capital in the market.

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 but consistent with accounting policies applied in the financial statements. 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 33.

Business performance net profit attributable to EnQuest PLC shareholders	2023 $'000	2022 $'000
Reported net profit/(loss) (A)	(30,833)	(41,234)
Adjustments - remeasurements and exceptional items (note 4):
Unrealised gains on derivative contracts (note 19)	24,631	9,575
Net impairment (charge)/reversal to oil and gas assets (note 10, note 11 and note 12)	(117,396)	(81,049)
Finance costs on Magnus contingent consideration (note 6)	(58,854)	(36,410)
Change in Magnus contingent consideration (2023: notes 5(d); 2022: notes 5(d) and 5(e))	69,665	(232,500)
Movement in other provisions	3,374	-
Other exceptional income (note 5(d))	4,127	6,636
Other exceptional expenses (note 5(e))	(10,731)	-
Other exceptional finance income (note 6)	-	2,148
Pre-tax remeasurements and exceptional items (B)	(85,184)	(331,600)
Tax on remeasurements and exceptional items (C)	25,138	78,020
Post-tax remeasurements and exceptional items (D = B + C)	(60,046)	(253,580)
Business performance net profit attributable to EnQuest PLC shareholders (A - D)	29,213	212,346

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 reserve based lending ('RBL') facility and term loan. 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/(loss) before tax and finance income/(costs).

Adjusted EBITDA	2023 $'000	2022 $'000
Reported profit from operations before tax and finance income/(costs)	456,227	411,887
Adjustments:
Remeasurements and exceptional items (note 4)	26,330	297,338
Depletion and depreciation (note 5(b) and note 5(c))	298,308	333,248
Inventory revaluation	(622)	763
Change in provision (note 5(d) and note 5(e))	32,764	(42,823)
Net foreign exchange loss/(gain) (note 5(d) and 5(e))	11,659	(21,329)
Adjusted EBITDA (E)	824,666	979,084

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	2023 $'000	2022 $'000
Available cash	313,028	293,866
Restricted cash	544	7,745
Total cash and cash equivalents (F) (note 14)	313,572	301,611
Available credit facilities	518,794	505,692
Credit facility - drawn down	(290,000)	(405,692)
Letter of credit (note 18)	(43,545)	(52,700)
Available undrawn facility (G)	185,249	47,300
Total cash and available facilities (F + G) ⁽ⁱ⁾	498,821	348,911

(i) Includes $19.0 million in relation to a vendor loan facility which expired on 1 January 2024. This facility is currently being renegotiated.

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 deleveraging 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	2023 $'000	2022 $'000
Borrowings (note 18):
RBL facility	135,080	395,391
Term Loan facility	146,367	-
SVT working capital facility	29,784	12,275
Vendor loan facility	-	5,692
Borrowings (H)	311,231	413,358
Bonds (note 18):
High yield bond	294,276	291,185
Retail bonds	169,669	295,745
Bonds (I)	463,945	586,930
Non-cash accounting adjustments (note 18):
Unamortised fees on loans and borrowings	8,553	4,609
Unamortised fees on bonds	10,724	13,815
Non-cash accounting adjustments (J)	19,277	18,424
Debt (H + I + J) (K)	794,453	1,018,712
Less: Cash and cash equivalents (note 14) (E)	313,572	301,611
EnQuest net debt (K - F) (L)	480,881	717,101

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 the Group's ability to settle its debt. This is a helpful metric to monitor the Group's progress against its strategic objective of deleveraging.

EnQuest net debt/adjusted EBITDA	2023 $'000	2022 $'000
EnQuest net debt (L)	480,881	717,101
Adjusted EBITDA (E)	824,666	979,084
EnQuest net debt/adjusted EBITDA (L/E)	0.6	0.7

Cash capital expenditure (nearest equivalent measure on an IFRS basis is purchase of property, plant and equipment) 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 materiality of the work programme and the focus on the Group's liquidity position and ability to reduce its debt.

Cash capital and decommissioning expense	2023 $'000	2022 $'000
Reported net cash flows from/(used in) investing activities	(206,895)	(161,247)
Adjustments:
Purchase of other intangible assets	876	1,199
Payment of Magnus contingent consideration - Profit share	65,506	45,975
Payment of Golden Eagle contingent consideration - Acquisition costs	50,000	-
Proceeds received from farm-down of equity interest in the EnQuest Producer FPSO	(55,800)	-
Interest received	(5,895)	(1,763)
Cash capital expenditure	(152,208)	(115,836)
Decommissioning expenditure	(58,911)	(58,964)
Cash capital and decommissioning expense	(211,119)	(174,800)

Free cash flow ('FCF') represents the cash a company generates, after accounting for cash outflows to support operations and 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.

Free cash flow	2023 $'000	2022 $'000
Net cash flows from/(used in) operating activities	754,244	931,553
Net cash flows (used in)/from investing activities	(262,695)	(161,247)
Net cash flows (used in)/from financing activities	(478,631)	(731,163)
Adjustments:
Proceeds from loans and borrowings⁽ⁱ⁾	(190,657)	(87,215)
Repayment of loans and borrowings⁽ⁱ⁾	427,736	567,020
Payment of Golden Eagle contingent consideration - Acquisition costs	50,000	-
Free cash flow	299,997	518,948

(i) For the prior year, $21.7 million has been reclassed between proceeds from loans and borrowings and repayments of loans and borrowings to better represent the substance of the transaction

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.

Revenue sales	2023 $'000	2022 $'000
Revenue from crude oil sales (note 5(a)) (M)	1,127,419	1,517,666
Revenue from gas and condensate sales (note 5(a)) (N)	338,973	514,206
Realised (losses)/gains on oil derivative contracts (note 5(a)) (P)	(11,264)	(203,741)

Barrels equivalent sales	2023 kboe	2022 kboe
Sales of crude oil (Q)	13,714	14,786
Sales of gas and condensate(i)	4,107	3,366
Total sales (R)	17,821	18,152

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

Average realised prices

2023

$/Boe

2022

$/Boe

Average realised oil price, excluding hedging (M/Q)

82.2

102.6

Average realised oil price, including hedging ((M + P)/Q)

81.4

88.9

Operating costs ('opex') is a measure of the Group's cost management performance (reconciled to reported cost of sales, the nearest equivalent measure on an IFRS basis). 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	2023 $'000	2022 $'000
Reported cost of sales (note 5(b))	946,752	1,200,706
Adjustments:
Remeasurements and exceptional items (note 5(b))	(5,650)	(4,900)
Depletion of oil and gas assets (note 5(b))	(292,199)	(327,027)
Credit/(charge) relating to the Group's lifting position and inventory (note 5(b))	4,244	15,568
Other cost of operations⁽ⁱ⁾ (note 5(b))	(305,919)	(487,831)
Operating costs	347,228	396,516
Less: realised loss/(gain) on derivative contracts (S) (note 5(b))	2,839	(5,418)
Operating costs directly attributable to production	350,067	391,098
Comprising of:
Production costs (T) (note 5(b))	308,331	347,832
Tariff and transportation expenses (U) (note 5(b))	41,736	43,266
Operating costs directly attributable to production	350,067	391,098

(i) Includes $294.0 million (2022: $452.8 million) of purchases and associated costs of third-party gas not required for injection activities at Magnus which is sold on

Barrels equivalent produced

2023

kboe

2022

kboe

Total produced (working interest) (V)⁽ⁱ⁾

15,992

17,250

(i) Production for 2023 includes 604 kboe associated with Seligi gas

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	2023 $/Boe	2022 $/Boe
Production costs (T/V)	19.3	20.2
Tariff and transportation expenses (U/V)	2.6	2.5
Total unit opex ((T + U)/V)	21.9	22.7
Realised (gain)/loss on derivative contracts (S/V)	(0.2)	0.3
Total unit opex including hedging ((S + T+ U)/V)	21.7	23.0

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