EnQuest PLC Half-year Results

RNS Number : 9821C

EnQuest PLC

05 September 2024

EnQuest PLC

Results for the six months ended 30 June 2024

5 September 2024

Unless otherwise stated, all figures are in US Dollars.

Comparative figures for the Income statement relate to the period ended 30 June 2023 and the Balance sheet as at 31 December 2023. 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 has continued to deliver strong uptime performance across our portfolio in the first half of the year, with production to the end of June averaging 42.8 Kboepd. With positive free cash flow generation and the cash completion of the Bressay farm down deal, the Group has continued to delever its Balance Sheet, with EnQuest net debt reduced to $321 million at 30 June. We have a significant work programme in the second half of the year, including drilling at Magnus, continued capital investment in Malaysia and decommisioning at Heather and Thistle. We remain on track to plug and abandon 60% of our suspended & shut-in wells across the portfolio by the end of 2024. At the Sullom Voe Terminal, we are progressing the transformative New Stabilisation Facility project and, through Veri Energy, we continue to advance our new energy and decarbonisation projects.

"We are disappointed with the ongoing application of the Energy Profits Levy despite operating in an environment where no windfall conditions exist. The current fiscal regime is causing irreversible damage to an indigenous and strategically important UK industry. The UK energy industry needs a progressive tax regime that recognises the maturity of the North Sea and re-establishes the UK as a globally competitive investment basin. The oil and gas sector is the key to a Just Energy Transition, protecting the skills, jobs and resources required to deliver the decarbonisation projects of the future and, with stability and the right fiscal stimulus, can deliver material UK economic growth through billions of pounds of investment-ready projects. EnQuest has to date invested over £4 billion in the UK and has the capacity and opportunities to do so again.

"The Group's growth strategy remains robust, with a focus on delivering a transformative UK acquisition; utilising our differentiated operating capability and significant tax asset to deliver material incremental value. Given the prevailing tax regime, we are targeting UK portfolios with limited capital reinvestment programmes. Internationally, we are working on a number of growth opportunities in South East Asia where the return on capital investment is compelling. The work we have done over the past seven years to strengthen our balance sheet gives us choices, and we will continue to make value-adding strategic decisions for our shareholders."

H1 2024 performance

· Reported cash generated from operations was $368.9 million (2023: $370.4 million); with cash capital expenditure of $95.0 million (2023: $80.0 million) and cash abandonment expenditure of $31.5 million (2023: $29.3 million).

· Net production averaged 42,771 Boepd (2023: 45,480 Boepd); strong uptime across the portfolio offset by minor delays to the Magnus five-yearly rig recertification programme and the failure of an infill well on the non-operated Golden Eagle asset.

· Revenue and other operating income totalled $586.0 million (2023: $770.4 million). Oil revenue was largely flat ($523.1 million; 2023: $540.1 million). Gas revenue fell on lower prices and reduced third party volumes transported over Magnus - the impact of which was offset in cost of sales.

· Reported profit after tax was $30.3 million (2023: loss of $21.2 million).

· EnQuest net debt was reduced by $159.9 million, to $321.0 million at 30 June 2024. The Group fully repaid its RBL and EnQuest maintained strong liquidity - with total cash and available facilities of $566.0 million (end 2023: $498.8 million).

· EnQuest's net debt to EBITDA ratio at 30 June was 0.4x - moving beyond the Group's stated leverage target of 0.5x.

· This provides a platform for transformational transactional growth, enhanced by the Group's advantaged UK tax position.

· EnQuest's $15 million share buy back programme commenced in April, with share purchases totalling c.$2.5 million at 30 June 2024. Planned Treasury repurchases were completed in August - all additional shares purchased will now be cancelled.

2024 guidance and outlook

The Group remains on track to deliver net production within the guidance range of 41,000 to 45,000 Boepd set at the start of the year. In H1 2024 the Magnus five yearly rig recertification was completed successfully but a minor delay and remedial works meant Magnus drilling and well interventions recommenced later than planned. This, and the previously reported failure of an infill well on the non-operated Golden Eagle field, mean full year production is now expected to be in the lower half of the guided range.

Full year expectations for operating, cash capital and abandonment expenditures remain unchanged from the Group's original guidance at c. $415 million, $200 million and $70 million, respectively.

For the period July to December 2024, the Group has hedged c.5.4 MMbbls of production through 4.6 MMbbls of put options with a floor price of $60/bbl and 0.8 MMbbls of swaps at c.$87/bbl. The Group has hedged a total of c.1.6 MMbbls in 2025 through the use of put options, all with the same floor of $60/bbl.

EnQuest's business development team is very active as the Group looks to deliver transformative growth and will remain disciplined to ensure shareholder value.

Production and financial information

Business performance measures	For the period to 30 June 2024	For the period to 30 June 2023	Change %
Production (Boepd)¹	42,771	45,480	(6.0)
Revenue and other operating income ($m)²	587.9	732.7	(19.8)
Realised oil price ($/bbl)^2,3	83.4	75.8	10.0
Operating costs ($m)³	183.0	162.7	12.5
Average unit operating costs ($/Boe)³	22.8	19.7	15.7
Adjusted EBITDA ($m)³	367.5	399.2	(7.9)
Cash expenditures ($m)	126.5	109.3	15.7
Capital	95.0	80.0	18.7
Abandonment	31.5	29.3	7.4
Free cash flow ($m)³	55.5	140.0	(60.4)
	30 June 2024	31 December 2023
EnQuest net debt ($m)³	(321.0)	(480.9)	(33.3)

Statutory IFRS measures	For the period to 30 June 2024	For the period to 30 June 2023	Change %
Reported revenue and other operating income ($m)⁴	586.0	770.4	(23.9)
Reported gross profit ($m)	233.7	287.1	(18.6)
Reported profit/(loss) after tax ($m)	30.3	(21.2)	(242.9)
Reported basic earnings/(loss) per share (cents)	1.6	(1.2)	(233.3)
Cash generated from operations ($m)	368.9	370.4	(0.4)
Net increase/(decrease) in cash and cash equivalents ($m)⁵	27.0	(18.1)	(249.2)

Notes:

¹ Production figure for first half of 2024 includes 1,614 Boepd associated with Seligi gas (2023: 660 Boepd)

² Including realised losses of $10.7 million (2023: realised losses of $22.2 million) associated with EnQuest's oil price hedges

³ See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 32. Note, EnQuest defines net debt as excluding finance lease liabilities

⁴ Including net realised and unrealised losses of $12.6 million (2022: net realised and unrealised gains of $15.5 million) associated with EnQuest's oil price hedges

⁵ Excludes foreign exchange impact of $(3.3) million (2023: $(0.3) million)

- Ends -

For further information, please contact:

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

Teneo	Tel: +44 (0)20 7353 4200
Martin Robinson
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's investor relations team will be hosting a presentation via Investor Meet Company, primarily focused on the Company's retail investors on 12 September 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 the Company 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.

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.

Operating review

Upstream operations

Group performance summary

Production of 42,771 Boepd reflected strong production efficiency across the operated portfolio, partially offsetting natural field declines. North Sea production was impacted by minor delays to the five-yearly rig recertification work at Magnus, subsequent interventions meaning wells were offline longer than planned, and the failure of one infill well on the non-operated Golden Eagle field.

In light of proposed changes to the UK fiscal system, the Group will continue to evaluate its programme of capital investment to ensure the protection and enhancement of value for investors.

UK operations

Magnus

Average production for the first six months of 2024 was 15,163 Boepd, 8.3% lower than the first half of 2023 (16,530 Boepd). Production efficiency for the period was 86% (2023: 91%).

The Magnus five-yearly rig recertification scope was completed in the first half of the year but some of the planned well intervention work required rig remediation, which resulted in wells being offline for longer than planned. Higher than anticipated decline in one Magnus well was mitigated by a gas lift optimisiation campaign, which has added over 1,000 Boepd of incremental oil.

EnQuest remains focused on the management of key Magnus topside infrastructure and targeted investment to optimise equipment, reduce obsolescence and continue to deliver top quartile operational uptimes. The asset team is also focused on enhanced water injection and reservoir sweep including the conversion of a high water cut production well to water injection, which is expected to increase pressure within that area of the reservoir to boost production.

The Magnus maintenance shutdown is ongoing and is targeted for completion within the original 21-day plan.

Kraken

Average net production of 13,637 Boepd (2023: 13,082 Boepd) in the first half of 2024 was driven by 98.5% production uptime and 97% water injection efficiency. This exemplary performance is testament to the focus and collaboration between the EnQuest and Bumi Armada operational teams, and the parties are undertaking further process work to extend this excellent performance.

The Group is focused on enhancing the next phase of Kraken operations and is working with its joint venture partner to finalise infill drilling plans for 2025. Work is ongoing to mature the Enhanced Oil Recovery ('EOR') project, which presents a material upside to the existing Kraken base reservoir performance. The EnQuest team is advancing the Bressay gas import project as a subsea tie-back to Kraken, which will displace the majority of the diesel currently used to power Kraken operations; driving a material reduction in FPSO emissions and materially reducing operating costs. In the second half of 2024, trials will also commence to assess the potential for hydrogenated vegetable oil to be used as a diesel alternative for the equipment that cannot be run on gas.

The Kraken maintenance shutdown is ongoing and is expected to be completed within ten days (six days full shutdown and four days on single train operations). The key scope to be completed is the five-yearly swivel inspection.

Golden Eagle

Average net production in the first half of the year was 3,614 Boepd net (2023: 4,545 Boepd), with asset production efficiency of around 94% (2023: 91%).

The 2023/24 platform drilling programme on this non-operated asset concluded in early August with the rig now off-station. Two of the three producers have been successfully brought online although, as previously reported, the second well in the sequence did not encounter sufficient hydrocarbon bearing sands so was not completed. The fourth well, which is a water injector, is in the process of being brought online.

Other Upstream assets

Production for the first six months of 2024 averaged 2,637 Boepd (2023: 3,105 Boepd). This was driven by natural field decline, partially offset by strong uptime of 89% (2023: 95%) at the Greater Kittiwake Area ('GKA'). The planned maintenance shutdown at GKA was delivered within the ten-day plan, with all scopes completed.

The Group has reached agreement with Shell and Dana Petroleum that EnQuest will be the GKA decommissioning operator, with Shell transferring its decommissioning management role to EnQuest. This joint venture decision recognises EnQuest's ability to deliver safe results, market-leading decommissioning performance and efficiencies of cost and schedule.

Malaysia operations

For the first six months of 2024, average production in Malaysia was 7,720 Boepd (2023: 8,218), with production uptime remaining high at 93% and benefitting from availability of all compression units this year. Seligi gas, which is produced and handled by EnQuest in exchange for a gas handling and delivery fee, represented 1,614 Boepd of year to date production. Discussions are ongoing between EnQuest and Petronas, seeking to expand on the existing foundational strategic agreement relating to Seligi gas.

The Group has completed all three wells in the 2024 infill drilling programme, with production rates in line with expectations. Three workover wells have been completed in the first half of the year and the Group will continue with its idle well restoration programme for the remainder of 2024. The 2024 shutdown is planned for the end of the third quarter to complete critical integrity and maintenance works, with a turbine control panel upgrade scheduled.

EnQuest was awarded two accolades at the Malaysia Upstream Awards, including Operator of the Year, and has reaffirmed its commitment to investment in the PM8/Seligi asset by the sanction of a four-well drilling campaign in 2025.

Decommissioning

Heather and Thistle well plug and abandonment ('P&A') campaigns are progressing well with five wells completed at Heather and a further seven wells completed at Thistle during the first half of 2024. The Group continues to demonstrate top quartile performance in delivering these significant decommissioning projects and remains on track to complete the P&A of 25 wells (11 at Heather and 14 at Thistle) in 2024. This work is being executed at sector leading cost 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.£2.6 million, 40% lower than the industry benchmark of c.£4.3 million.

The Heather project team expects to disembark the platform in the first quarter of 2025, having completed a 39 well P&A campaign. At Thistle, the team aim to complete disembarkation by the end of 2025 following the P&A of 41 wells in total. Preparatory works have commenced at both Heather and Thistle in support of the platform removal workscopes. Across the North Sea portfolio, EnQuest remains on track to abandon 60% of all suspended and shut-in wells within five years of cessation of production by the end of 2024.

EnQuest is also planning the P&A of Magnus subsea wells, commencing in 2027, to be followed by a 33 subsea well P&A programme across the Alma/Galia, Dons and Broom fields. The EnQuest team continues to work on the basis that subsea decommissioning activities can be optimised by utilising a portfolio approach across the fields, with the scheduling of activity primarily driven by well integrity.

Midstream

Within its Midstream directorate, EnQuest operates the Sullom Voe Terminal ('SVT') on Shetland and around 1,000km of pipelines. Through the first half of 2024, 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. The SVT Power Station achieved 100% power delivery throughout the period.

EnQuest remains focused on right-sizing SVT for future operations and is progressing strategic projects to connect the terminal to the UK's electricity grid and to construct 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 EQUANS-operated Sullom Voe Power Station. NSF will right-size the terminal's oil stabilising (removing gas from the oil so that it is safe for onwards transportation) and processing capacity to meet the future production profile associated with the East of Shetland offshore fields.

EnQuest has commenced phased decommissioning of the existing oil stabilisation, processing and storage facilities. This is a significant step in effectively managing the integrity of the terminal infrastructure and creates the potential for its repurposing for new business development, including the new energy projects managed by Veri Energy.

Veri Energy

Renewable Power

Veri is exploring the potential to develop onshore wind power at the Sullom Voe site and has progressed concept development, preparatory environmental screening and data acquisition to support this. A small scale project, harnessing the wind potential around Shetland and established technology could initially provide cost-competitive, renewable power to existing users at the site reducing emissions. In time, this initial project could be supplemented with additional build-out on site and surrounding areas. Veri is also exploring the feasibility of utilising existing infrastructure and synergies with its carbon storage projects to generate additional baseload renewable power onsite through carbon storage enabled power.

Carbon Storage

Veri continues to progress the four carbon storage licences awarded in 2023 by the North Sea Transition Authority ('NSTA') and has, in addition to completing early risk assessment reports for each of the projects, successfully fulfilled its firm licence commitment to reprocess and reinterpret seismic data. This exercise provides Veri with improved data to further characterise and optimise design of the storage complexes. With an ultimate aim of leveraging existing infrastructure (including the East of Shetland Pipeline System) to transport and store up to 10Mtpa of CO₂ from isolated emitters in the UK and Europe, the initial focus will be on developing the Thistle storage area to deliver around 2Mtpa capacity prior to 2030. Veri is currently assessing technical partners to support the delivery of the project to supplement the extensive in-house subsurface, drilling and facilities expertise within the Group.

Veri continue to see interest in its flexible carbon storage solution from emitters both in the UK and Europe and is also evaluating opportunities to decarbonise some of the Group's existing portfolio.

Green Hydrogen & Derivatives

Veri Energy is progressing the evaluation of a 50-300 megawatt green hydrogen project at Sullom Voe. Veri is finalising its consortium to deliver the front-end engineering and design study for the project, which has the backing of the UK Government's net zero hydrogen fund via a grant of £1.74 million.

Environmental, Social and Governance review

The health, safety and wellbeing of our people and delivering Safe Results is EnQuest's top priority. The Group has delivered two years of LTI free performance in Malaysia and was presented with the HSE Excellence Award at the Malaysia Upstream Awards in May. EnQuest's North sea LTI performance in the first half of the year was however not at an acceptable level, resulting in increased focus across the organisation on driving personal responsibility for safety, increased hazard awareness and supervision at the worksite. The Group has a strong HSEA and process safety culture and is working with key contractors to ensure an immediate improvement in safety performance.

The Group continues to make excellent progress in reducing its absolute Scope 1 and 2 emissions, with the achievement of national emissions reduction targets and the drive to net zero being a core focus area. Since 2018, EnQuest's UK Scope 1 and 2 emissions have reduced by more than 40%, which is significantly ahead of the UK Government's North Sea Transition Deal target of achieving a 10% reduction in Scope 1 and 2 CO₂ equivalent emissions by 2025 and close to the 50% reduction targeted by 2030. At SVT, EnQuest has two projects in-flight which, together, will reduce terminal emissions by c.90%. The Group also plans to materially reduce the carbon footprint of the Kraken FPSO by replacing diesel fuel through a gas tie-back to Bressay.

Through the work being progressed by the Group's wholly-owned subsidiary, Veri Energy, three discrete and scalable decarbonisation opportunities have the potential to deliver on EnQuest's commitment to reach net zero for scope 1 and scope 2 emissions by 2040 - the CCS project alone has the potential to store up to 10 million tonnes of CO₂ per annum, which represents a multiple of the Group's existing emissions footprint.

Corporate governance is an essential part of EnQuest's operational and business framework, supporting both risk management and the Group's Core Values. The Board remains focused on Board and executive succession planning, with evolution of the Group's strategy necessitating changes to align competencies more closely with its delivery. As part of the Board refresh, and following shareholder approval at the 2024 Annual General Meeting, Jonathan Copus has joined the EnQuest Board as an Executive Director, with Rosalind Kainyah MBE and Marianne Daryabegui joining the Board as Non-Executive Directors. As previously announced, Salman Malik, Rani Koya and Liv Monica Stubholt stepped down as Directors at the AGM.

Financial Review

All figures quoted are in US Dollars unless otherwise stated.

Introduction

EnQuest continues to make progress against its financial priorities. EnQuest net debt has been reduced by a further $159.9 million since 31 December 2023, to $321.0 million as at 30 June 2024 - driven by free cash flow generation of $55.5 million and cash receipts of $108.8 million associated with the December 2023 farm-down of interests in Bressay. Total cash and available facilities at 30 June 2024 totalled $566.0 million (31 December 2023: $498.8 million).

In late April, the Group commenced its $15 million share buy back programme and had purchased $2.5 million at 30 June 2024.

EnQuest continues to maintain a strong focus on capital discipline and cost control. As anticipated, EnQuest's increased share of throughput at SVT led to higher tariff costs in the period, noting future cost and emission reductions are expected at completion of the ongoing decarbonisation projects at the terminal. Consequently, unit operating expenses in the period averaged $22.8/Boe (2023: $19.7/Boe). The Group reports an IFRS post-tax profit of $30.3 million for the period to 30 June 2024 (30 June 2023: IFRS post-tax loss of $21.2 million).

The ongoing application and proposed changes of the UK EPL on the industry at a time where no windfall conditions exist is creating volatility in financial results and undermining the global competitiveness and the investment landscape of the industry. However, with a strong liquidity position and a strategic tax advantage in the UK North Sea, EnQuest remains well placed to pursue growth opportunities in the North Sea and internationally. EnQuest continues to explore ways to leverage its capabilities to drive value through transformational organic and acquisition opportunities.

Income statement

Revenue

Group production averaged 42,771 Boepd (6.0% lower than in H1 2023, 45,480 Boepd). Oil accounted for 87.9% of this output (H1 2023: 90.0%).

Brent crude oil prices rose 5.0% year-on year to average $83.7/bbl (H1 2023: $79.7/bbl) but average day-ahead gas price declined 32.4% to 73p/therm (H1 2023: 108p/therm). Excluding the impact of hedging, EnQuest realised an average oil price of $85.1/bbl (H1 2023: $79.0/bbl). Post-hedging, the realised oil price was $83.4/bbl, which was 10.0% higher than in H1 2023 ($75.8/bbl).

Reflecting significantly lower gas prices and onward sales of gas volumes from third-party West of Shetland fields transported across the Magnus facility, reported revenue for H1 2024 totalled $586.0 million. This was 23.9% lower than the same period in 2023 ($770.4 million). Oil revenue was just 3.1% lower, totalling $523.1 million (H1 2023: $540.1 million), but condensate and gas revenue fell by 65.6%, to $73.4 million (H1 2023: $213.2 million). Gas revenue mainly relates to gas purchases from West of Shetland fields that were not required for injection activities at Magnus. The contribution of these volumes to revenue is therefore offset through a charge to cost of sales.

Tariffs and other income generated $2.1 million (2023: $1.5 million), which includes income associated with the transportation of Seligi Associated gas. Realised losses on commodity hedges totalled $10.7 million (2023: losses of $22.2 million). Unrealised losses on these contracts (from mark-to-market movements) totalled $1.9 million (2023: unrealised gains of $37.6 million).

Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP measures' starting on page 32

Cost of sales¹

Cost of sales were $352.3 million for the six months ended 30 June 2024, which was 27.1% lower than in H1 2023 ($483.2 million).

Production costs were broadly flat, totalling $143.6 million ($18.4/Boe) but operating costs increased by $20.3 million to $183.0 million. This rise was expected as it reflected a planned increase to EnQuest's share of throughput at SVT ahead of future forecast cost and emission reductions at the terminal following the completion of the current decarbonisation projects on site. As a result, unit operating costs (excluding hedging losses) increased by 15.7% to $22.8/Boe (2023: $19.7/Boe).

	H1 2024 $ million	H1 2023 $ million
Production costs	143.6	145.5
Tariff and transportation expenses	34.0	16.1
Realised loss/(gain) on derivatives related to operating costs	5.4	1.1
Operating costs	183.0	162.7
(Credit)/charge relating to the Group's lifting position and hydrocarbon inventory	(22.8)	(15.3)
Other cost of operations	63.3	197.9
Depletion of oil and gas assets	136.7	147.9
Other cost of sales	(7.9)	(9.9)
Cost of sales	352.3	483.2
Unit operating cost²	$/Boe	$/Boe
- Production costs	18.4	17.7
- Tariff and transportation expenses	4.4	2.0
Average unit operating cost	22.8	19.7

Notes:

¹ See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 32

² Calculated using production on a working interest basis including Seligi Associated Gas

The credit relating to the Group's lifting position and hydrocarbon inventory for the six months ended 30 June 2024 was $22.8 million (H1 2023: credit of $15.3 million) - the net underlift position increasing to $29.0 million at 30 June 2024 (31 Dec 2023: $3.5 million.

The cost of Magnus third-party gas purchases that are sold on is reported within 'other cost of operations'. These costs fell significantly to $63.2 million (H1 2023: $197.9 million), due to lower third-party volumes and materially lower gas prices,

Depletion expense ($136.7 million) was 7.6% lower than H1 2023 ($147.9 million), mainly reflecting lower production.

Impairment

In the period, the Group recognised a non-cash net impairment charge of $21.0 million (2023: $96.5 million). This charge reflected changes in the production profile on the non-operated Golden Eagle field, higher decommissioning cost estimates and the previous Conservative UK Governments announcement that it intended to extend the duration of the UK Energy Profits Levy by one year to 31 March 2029, partially offset by an increase in EnQuest's future oil price assumptions and a lower discount rate of 10.5% (2023: 11.0%).

Other income and expenses

The Group has recognised net expense in the period $0.4 million (2023: net income of $35.7 million). Underlying this are: a $13.8 million non-cash expense relating to the periodic review of the net fair value of the contingent consideration owed to bp relating to the Magnus acquisition, driven by higher oil prices (2023: $43.5 non-cash income, driven by an increase in the discount rate applied); a non-cash charge of $4.9 million due to a net increase in the decommissioning provision of fully impaired non-producing assets, driven by general inflationary pressures (2023: non-cash charge of $7.2 million); a foreign exchange gain of $7.8 million, reflecting a favourable movement in the Sterling to US Dollar exchange rate (2023: $17.7 million foreign exchange losses); and $1.6 million of insurance receipts, primarily related to the 2023 Kraken downtime (2023: release of the $5.2 million Golden Eagle acquisition-related provision and $4.1 million insurance income related to Malaysian riser repairs).

Other expenses also include costs associated with Veri Energy, which in H1 2024 totalled $1.1 million (2023: $0.1 million).

Adjusted EBITDA

Adjusted EBITDA for the period totalled $367.5 million, down 7.9% compared to the same period in 2023 ($399.2 million). Underlying this fall are: decarbonisation project tariffs at SVT and lower revenue.

EnQuest's net debt to last 12-month adjusted EBITDA ratio at 30 June 2024 equalled 0.4x. This was below the Group's targeted level of 0.5x (31 December 2023: 0.6x).

Adjusted EBITDA	H1 2024 $ million	H1 2023 $ million
Profit/(loss) from operations before tax and finance income/(costs)	208.6	225.2
Unrealised hedge loss/(gain)	1.9	(37.6)
Depletion and depreciation	139.8	150.9
Impairment charge	21.0	96.5
Net other (income)/expense	17.2	(45.6)
Foreign exchange and UKA forward purchase (gains)/losses	(7.9)	(9.9)
Change in well inventories	(5.2)	2.0
Net foreign exchange (gain)/loss	(7.9)	17.7
Adjusted EBITDA¹	367.5	399.2

Note:

¹ See reconciliation of Adjusted EBITDA within the 'Glossary - Non-GAAP measures' starting on page 32

Finance costs

EnQuest's overall finance costs fell by 13.4%, to $97.3 million (H1 2023: $112.4 million). A significantly lower level of outstanding loans and borrowings resulted in a lower overall interest charge of $36.6 million (2023: $45.2 million) despite higher prevailing interest rates. This was partially offset by higher refinancing fees (2024: $5.7 million; 2023: $3.9 million).

Finance charges included the unwinding of discounting on contingent consideration related to the acquisition of Magnus of $28.7 million (H1 2023: $31.1 million, with $30.4 million related to Magnus and $1.7 million related to the Golden Eagle acquisition) and decommissioning and other provisions (2024: $13.7 million; 2023: $12.7 million). Lease liability interest costs totalled $16.6 million (2023: $20.5 million) and there were other financial expenses of $2.6 million (2023: $3.2 million), which primarily are the cost for surety bonds that provide security for decommissioning liabilities.

Profit/loss before tax

Reflecting the movements above, the Group's profit before tax was $111.3 million (2023: profit of $112.9 million).

Taxation

The 2024 half year tax charge of $80.9 million includes a current cash tax charge of $41.1 million, of which $34.1 million relates to the UK Energy Profits Levy ('EPL') (2023: $134.1 million, inclusive of a current cash tax charge of $85.6 million of which $73.8 million was EPL related).

The Group's effective tax rate for the period was a charge of 72.7% (Period ended 30 June 2023: 118.8%). On 29th July 2024, the UK government announced further changes to the EPL - increasing the rate and duration of the levy and treatment of allowances from 1 November 2024. See note 16 for further information. As these measures had not been enacted at the balance sheet date, there is no impact on the 30 June 2024 balance sheet.

EnQuest's strategic UK North Sea tax asset was estimated at $1,928.8 million at 30 June 2024 (31 December 2023: $2,007.9 million) - the reduction in the period reflecting utilisation against the Group's profits before tax.

Reflecting this tax position, no significant corporation tax or supplementary charge is expected to be paid on UK operational activities for the foreseeable future. The Group expects to continue to make Energy Profits Levy payments for the duration of the EPL, and EnQuest also pays cash corporate income tax on its Malaysian assets.

Profit/loss for the period

The Group's total profit after tax was $30.3 million, which compares to an H1 2023 loss of $21.2 million.

Earnings per share

The Group's reported basic earnings per share was 1.6 cents (2023 loss per share: 1.2 cents) and reported diluted earnings per share was 1.6 cents (2023 loss per share: 1.2 cents).

Cash flow, EnQuest net debt and liquidity

Driven by continued free cash flow generation in the first half of 2024 and the receipt in Q1 of $108.8 million related to the 2023 Bressay transaction, EnQuest net debt at 30 June 2024 totalled $321.0 million. This was a $159.9 million reduction compared with EnQuest net debt of $480.9 million at 31 December 2023.

The movement in EnQuest net debt was as follows:

	$ million
EnQuest net debt 1 January 2024	(480.9)
Net cash flows from operating activities	323.7
Cash capital expenditure	(95.0)
Magnus profit share payments	(48.1)
Net interest and finance costs paid	(39.8)
Finance lease payments	(85.0)
Bressay transaction receipts¹	108.8
Other movements, primarily net foreign exchange on cash and debt	(4.7)
EnQuest net debt 30 June 2024²	(321.0)

Note:

¹ Primarily related to the vendor financing facility

² See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 32.

Reported net cash flows from operating activities for the period were $323.7 million. This was 12.7% below the comparative period of 2023 ($371.0 million), however H1 2023 operating cash flow was boosted by the receipt of a joint venture advance cash call ($39.5 million) and the refund of the EPL instalment payment made in December 2022 ($37.4 million). Clean of these benefits, year-on-year cash flow from operating activities was 10.1% higher.

Reported net cash flows used in investing activities decreased year-on-year by $85.4 million, to $30.5 million (H1 2023: $115.9 million). This principally reflects: receipts associated with the Bressay transaction ($108.8 million; H1 2023: nil); higher capital expenditures ($95.0 million - primarily related to the Magnus 5-yearly rig recertification workscope, Golden Eagle well campaign and decarbonation projects at SVT (H1 2023: $80 million)); and additional Magnus profit share payments (2024: $48.1 million; H1 2023: $38.2 million).

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

Capital expenditure	H1 2024 $ million	H1 2023 $ million
North Sea	84.4	64.5
Malaysia	9.3	11.0
Exploration and evaluation	1.3	4.5
	95.0	80.0

The Group utilised $266.3 million of cash in financing activities (2023: $273.3 million). This included further net repayments of the Group's loans and borrowings totalling $134.8 million (2023: $158.1 million). In Q1 2024, EnQuest repaid in full its RBL facility. The facility remains available to EnQuest for future drawdown.

Interest costs on the Group's borrowings totalled $44.0 million (2023: $51.7 million) and an additional $85.0 million was paid in relation to finance leases (2023: $63.4 million).

EnQuest also repurchased $2.5 million of shares as part of a targeted $15.0 million share buy back programme.

In aggregate, the Group's cash and cash equivalents increased $23.7 million in the first half of 2024. This increase was primarily driven by the receipt in Q1 of $108.8 million related to the 2023 Bressay transaction and free cash flow generation of $55.5 million, offset by the $140.0 million repayment of the Group's RBL facility and share repurchases made under EnQuest's share buy back programme. Free cash flow generation in the first half of 2024 was lower than the same period in 2023, with the first half of 2023 benefitting from the receipt of a joint venture advance cash call ($39.5 million) and the refund of the EPL instalment payment made in December 2022 ($37.4 million).

Net Debt	30 June 2024 $ million	31 December 2023 $ million
Bonds	473.6	474.7
Senior secured debt facility ('RBL')	-	140.0
Term Loan	150.0	150.0
SVT Working Capital Facility	34.8	29.8
Cash and cash equivalents	(337.3)	(313.6)
EnQuest net debt	321.0	480.9

Note:

1 See reconciliation of EnQuest net debt within the 'Glossary - Non-GAAP measures' starting on page 32

The Group ended the period with $337.3 million of cash and cash equivalents (31 December 2023: $313.6 million) and cash and available undrawn facilities at 30 June 2024 totalled $566.0 million (31 December 2023: $498.8 million). EnQuest continues to monitor market conditions and evaluate different options in relation to its capital structure, including potentially accessing the public debt capital markets.

Balance sheet

EnQuest's robust liquidity position enables the Group to continue delivering its capital-efficient programmes of capital investment and pursue transformational North Sea and International production acquisitions.

Assets

Total assets at 30 June 2024 reduced by 4.8% to $3,586.3 million (31 December 2023: $3,765.8 million). Driving this were: Bressay transaction receipts ($108.8 million); a reduction of $60.2 million in the Group's deferred tax asset (ring-fence corporation tax losses utilised in the period); and higher cash and cash equivalents of $23.7 million.

Liabilities

Total liabilities reduced by 6.3% to $3,100.9 million (31 December 2023: $3,309.0 million) - the Group continuing to make material debt repayments (the full $140.0 million of outstanding principal on the RBL was repaid in Q1 2024) and lease liabilities were reduced by $64.6 million.

Contingent consideration payments in the period (related to the acquisition of Magnus) totalled $48.5 million (2023: $38.2 million). This was largely offset by a net increase in the fair value and unwind of discount, which resulted in a marginally lower outstanding contingent consideration estimate of $501.7 million (31 December 2023: $507.8 million)

Total income tax liabilities, excluding deferred tax, increased by $30.8 million in the period to $216.3 million (31 December 2023: $185.5 million), with $170.7 million in current liabilities and $45.6 million in non-current liabilities.

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 Group's 2023 Annual report.

Going concern disclosure

In the first half of 2024, EnQuest reduced its net debt by a further $159.8 million (to $321.0 million). This was driven by robust free cash flow generation, totalling $55.5 million, and the cash receipt of $108.8 million associated with the December 2023 Bressay farm-down. With a strong cash balance and funds remaining available to draw down in the RBL (which was repaid in full in Q1 2024), the Group's cash and available facilities totalled $566.0 million at 30 June 2024, an increase of $67.2 million since 31 December 2023.

Against this robust backdrop, EnQuest continues to closely monitor and manage its funding position and liquidity risk, 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 forecast and approved business plan, underpin management's base case ('Base Case') and are in line with the Group's production guidance using an oil price assumption of $80.0/bbl for 2024 and 2025.

A reverse stress test has been performed on the Base Case indicating that an average oil price of c.$59/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'):

· 10.0% discount to Base Case prices resulting in Downside Case prices of $72.0/bbl for 2024 and 2025;

· Production risking of 5.0% for 2024 and 2025; and

· 2.5% increase in operating, capital and decommissioning expenditure for 2025.

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 half-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.

Risks and uncertainties

The Directors have reviewed the principal risks facing the Company and concluded the principal risks for the remaining six months of the financial year are unchanged from those described in the 2023 Annual Report and Accounts, which was published in April 2024. To reach this conclusion, the Directors considered the changes in the external environment during the recent period that could threaten the Company's business model, future performance, liquidity, and reputation. The Directors also considered management's view of the current risks facing the Company.

Accordingly, for the purposes of meeting the disclosure requirements of DTR 4.2.7(2), the Board believes that the Group's principal risks and uncertainties for the remaining six months are:

Principal risks and uncertainties

· Health, Safety and Environment ('HSE')

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

· Oil and gas prices

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

· Production

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

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

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

· Financial

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

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

· Competition

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

· IT security and resilience

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

· Portfolio concentration

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

· Subsurface risk and reserves replacement

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

· Project execution and delivery

· 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.

· Fiscal risk and government take

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

· International business

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

· Joint venture partners

· Failure by joint venture parties to fund their obligations.

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

· Reputation

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

· Human resources

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

Production details

Average daily production on a net working interest basis	For the period to 30 June 2024	For the period to 30 June 2023
	(Boepd)	(Boepd)
UK Upstream
- Magnus	15,163	16,530
- Kraken	13,637	13,082
- Golden Eagle	3,614	4,545
- Other Upstream¹	2,637	3,105
Total UK	35,051	37,262
Total Malaysia²	7,720	8,218
Total EnQuest	42,771	45,480

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

² Malaysia production figure for first half of 2024 includes 1,614 Boepd associated with Seligi gas (2023: 660 Boepd)

Group Income Statement

For the six months ended 30 June 2024

		30 June 2024			30 June 2023
	Notes	Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in period $'000	Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in period $'000
		Unaudited	Unaudited	Unaudited	Unaudited	Unaudited	Unaudited
Revenue and other operating income	5	587,932	(1,912)	586,020	732,738	37,617	770,355
Cost of sales		(360,164)	7,854	(352,310)	(493,140)	9,921	(483,219)
Gross profit/(loss)		227,768	5,942	233,710	239,598	47,538	287,136
Net impairment (charge)/reversal		-	(20,995)	(20,995)	-	(96,459)	(96,459)
General and administration expenses		(3,695)	-	(3,695)	(1,086)	-	(1,086)
Other income		18,744	1,645	20,389	8,292	52,803	61,095
Other expenses		(7,071)	(13,764)	(20,835)	(25,440)	-	(25,440)
Profit/(loss) from operations before tax and finance income/(costs)		235,746	(27,172)	208,574	221,364	3,882	225,246
Finance costs		(75,195)	(28,690)	(103,885)	(85,545)	(29,427)	(114,972)
Finance income		6,589	-	6,589	2,621	-	2,621
Profit/(loss) before tax		167,140	(55,862)	111,278	138,440	(25,545)	112,895
Income tax expense	6	(82,959)	2,029	(80,930)	(131,782)	(2,330)	(134,112)
Profit/(loss) for the period attributable to owners of the parent		84,181	(53,833)	30,348	6,658	(27,875)	(21,217)
Total comprehensive profit/(loss) for the period, attributable to owners of the parent				30,348			(21,217)

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

Earnings per share	7	$	$	$	$
Basic		0.044	0.016	0.004	(0.012)
Diluted		0.044	0.016	0.004	(0.012)

The attached notes 1 to 16 form part of these condensed Group financial statements.

Group Balance Sheet

At 30 June 2024

	Notes	30 June 2024 $'000	31 December 2023 $'000
		Unaudited	Audited
ASSETS
Non-current assets
Property, plant and equipment	8	2,297,987	2,296,740
Goodwill		134,400	134,400
Intangible assets		18,422	18,323
Deferred tax assets	6	479,915	540,122
Trade and other receivables		2,811	-
Other financial assets	10	37,454	36,282
		2,970,989	3,025,867
Current assets
Intangible assets		321	876
Inventories		46,674	84,797
Trade and other receivables		228,549	225,486
Current tax receivable	6	477	1,858
Cash and cash equivalents		337,319	313,572
Other financial assets	10	2,020	113,326
		615,360	739,915
TOTAL ASSETS		3,586,349	3,765,782
EQUITY AND LIABILITIES
Equity
Share capital and premium		394,060	393,831
Treasury shares	15	(2,479)	-
Share-based payment reserve		13,860	13,195
Retained earnings		80,050	49,702
TOTAL EQUITY		485,491	456,728
Non-current liabilities
Loans and borrowings	9	612,150	747,812
Lease liabilities		240,777	288,892
Contingent consideration	11	447,626	461,271
Provisions	12	726,398	715,436
Deferred income		138,095	138,416
Trade and other payables		26,333	32,917
Taxes payable	6	45,591	-
Deferred tax liabilities	6	57,288	77,643
		2,294,258	2,462,387
Current liabilities
Loans and borrowings	9	40,105	27,364
Lease liabilities		116,812	133,282
Contingent consideration	11	54,096	46,525
Provisions	12	70,050	79,861
Trade and other payables		336,959	347,409
Other financial liabilities	10	17,857	26,679
Current tax payable	6	170,721	185,547
		806,600	846,667
TOTAL LIABILITIES		3,100,858	3,309,054
TOTAL EQUITY AND LIABILITIES		3,586,349	3,765,782

The attached notes 1 to 16 form part of these condensed Group financial statements.

Group Statement of Changes in Equity

For the six months ended 30 June 2024

	Share capital and share premium $'000	Treasury shares $'000	Share-based payments reserve $'000	Retained earnings $'000	Total $'000
	Unaudited	Unaudited	Unaudited	Unaudited	Unaudited
Balance at 1 January 2023	392,196	-	11,510	80,535	484,241
Profit/(loss) for the period	-	-	-	(21,217)	(21,217)
Total comprehensive loss for the period	-	-	-	(21,217)	(21,217)
Share-based payment	-	-	1,353	-	1,353
Balance at 30 June 2023	392,196	-	12,863	59,318	464,377

Balance at 1 January 2024	393,831	-	13,195	49,702	456,728
Profit/(loss) for the period	-	-	-	30,348	30,348
Total comprehensive profit for the period	-	-	-	30,348	30,348
Issue of shares to Employee Benefit Trust	229	-	(229)	-	-
Share-based payment	-	-	894	-	894
Repurchase of shares (note 15)	-	(2,479)	-	-	(2,479)
Balance at 30 June 2024	394,060	(2,479)	13,860	80,050	485,491

The attached notes 1 to 16 form part of these condensed Group financial statements.

Group Statement of Cash Flows

For the six months ended 30 June 2024

	Notes	30 June 2024 $'000		30 June 2023 $'000
		Unaudited	Unaudited
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations	14	368,872		370,421
Cash (paid)/received on (purchase)/sale of financial instruments		(6,588)		(2,934)
Decommissioning spend		(31,516)		(29,333)
Income taxes (paid)/received		(7,029)		32,892
Net cash flows from/(used in) operating activities		323,739		371,046
INVESTING ACTIVITIES
Purchase of property, plant and equipment		(93,629)		(76,960)
Purchase of intangible oil and gas assets		(1,362)		(3,074)
Purchase of other intangible assets		(321)		-
Payment of Magnus contingent consideration - Profit share	11	(48,118)		(38,229)
Vendor financing facility receipt	10(a)	107,518		-
Proceeds from farm-down		1,263		-
Interest received		4,181		2,398
Net cash flows (used in)/from investing activities		(30,468)		(115,865)
FINANCING ACTIVITIES
Proceeds from loans and borrowings		19,735		21,468
Repayment of loans and borrowings		(154,528)		(179,591)
Payment for repurchase of shares	15	(2,479)		-
Payment of obligations under financing leases		(85,020)		(63,412)
Interest paid		(43,975)		(51,744)
Net cash flows (used in)/from financing activities		(266,267)		(273,279)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS		27,004		(18,098)
Net foreign exchange on cash and cash equivalents		(3,257)		(275)
Cash and cash equivalents at 1 January		313,572		301,611
CASH AND CASH EQUIVALENTS AT 30 JUNE		337,319		283,238
Reconciliation of cash and cash equivalents
Total cash at bank and in hand		327,848		275,922
Restricted cash⁽ⁱ⁾		9,471		7,316
Cash and cash equivalents per balance sheet		337,319		283,238

(i) At 30 June 2024, restricted cash represents $1.0 million on deposit relating to bank guarantees for the Group's Malaysian assets (2023: $7.3 million) and $8.4 million (2023: nil) held in escrow in relation to a dispute with a third-party contractor (see note 12)

The attached notes 1 to 16 form part of these condensed Group financial statements.

Notes to the Half Year Condensed Financial Statements

For the period ended 30 June 2024

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 principal activities of the Company and its subsidiaries (together the 'Group') are to responsibly optimise hydrocarbon production, leverage existing infrastructure, deliver a strong decommissioning performance and explore new energy and decarbonisation opportunities. The Group's half year condensed financial statements for the six months ended 30 June 2024 were authorised for issue in accordance with a resolution of the Board of Directors on 4 September 2024.

2. Basis of preparation

The interim condensed consolidated financial statements of the Group for the six months ended 30 June 2024 have been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted by the UK. 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 interim report does not include all the information and disclosures required in the annual financial statements and should be read in conjunction with the Group's annual financial statements for the year ended 31 December 2023.

The financial information contained in this announcement does not constitute statutory financial statements within the meaning of section 434 of the Companies Act 2006.

Consolidated statutory accounts for the year ended 31 December 2023, on which the auditor gave an unqualified audit report, have been filed with the Registrar of Companies.

The financial statements have been prepared on the going concern basis. Further information relating to the use of the going concern assumption is provided in the 'Going Concern' section of the Financial Review as set out on page 10. The interim financial statements have been reviewed by the auditor and its report to the Company is included within these interim financial statements.

Accounting policies

The accounting policies adopted in the preparation of the interim condensed financial statements for the six months ended 30 June 2024 are materially consistent with those followed in the preparation of the Group's financial statements for the year ended 31 December 2023. Any other standard, interpretation or amendment that was issued but not yet effective has not been adopted by the Group.

Critical accounting judgements and key sources of estimation uncertainty

Critical accounting judgements and key sources of estimation uncertainty were disclosed in the Group's 2023 annual report and accounts. These are reconsidered at the end of each reporting period to determine if any changes are required to judgements and estimates as a result of current market conditions. Key changes from those judgements and estimates disclosed in the Group's 2023 annual report and accounts are set out below:

Recoverability of asset carrying values

Oil price

The Group's un-hedged Brent oil price assumption was revised during the first half of 2024. The Group's Brent assumptions for the remainder of 2024 and 2026 have changed to reflect robust demand forecasts. The assumption for 2025 and the Group's longer term Brent price assumption is unchanged from that disclosed in the Group's 2023 annual report and accounts. See table below for summary of oil price assumptions used at 30 June 2024. The price assumptions used at the end of 2023 were $80.0/bbl (2024), $80.0/bbl (2025), $75.0/bbl (2026) and $77.0/bbl real thereafter, inflated at 2% per annum from 2027. See note 8 for oil price sensitivities.

Second

half 2024

2025

2026

2027>*

Brent oil ($/bbl)

85.0

80.0

77.0

*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. 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.

The Group uses proven and probable ('2P') reserves (see page 24 of the Group's 2023 Annual Report and Accounts) 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. At the half year, where appropriate, the Group has revised certain future production profiles as a result of the relevant cash generating unit's ('CGU') performance in the first half of 2024.

Discount rates

Impairment

The WACC rate applied to discount the future cash flows for calculating the CGU fair value less costs to dispose for impairment purposes was reassessed. Reflecting the Group's strengthened liquidity position and continued debt repayments, the rate has been reduced by 0.5% to 10.5% at 30 June 2024 (December 2023: 11.0%). See note 8 for related sensitivity analysis.

Decommissioning provision

The discount rate used for calculating the Group's decommissioning provision and the Thistle decommissioning-related provision was reassessed and, due to the prevailing macroeconomic environment, increased by 1.0% to 4.5% at 30 June 2024. See note 12 for related sensitivity analysis.

New and amended standards adopted by the Group

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

Amendments to IAS 7 and IFRS 7	Supplier Finance Arrangements
Amendments to IFRS 16	Lease Liability in a Sale and Leaseback
Amendments to IAS 1	Classification of Liabilities as Current or Non-current

3. Segment information

Segment information for the six month period is as follows:

Period ended 30 June 2024 $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(i)	Consolidated
Revenue and other operating income:
Revenue from contracts with customers	533,371	64,293	-	597,664	-	597,664
Other operating income/(expense) ⁽ⁱ⁾	810	-	122	932	(12,576)	(11,644)
Total revenue and other operating income/(expense)	534,181	64,293	122	598,596	(12,576)	586,020
Segment profit/(loss) before tax and finance income/(costs)(ii)	192,876	24,492	1,344	218,712	(10,138)	208,574

Period ended 30 June 2023 $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(i)	Consolidated
Revenue and other operating income:
Revenue from contracts with customers	685,980	68,141	-	754,121	-	754,121
Other operating income/(expense)⁽ⁱ⁾	653	-	132	785	15,449	16,234
Total revenue and other operating income/(expense)	686,633	68,141	132	754,906	15,449	770,355
Segment profit/(loss) before tax and finance income/(costs)(ii)	179,665	27,851	(6,521)	200,995	24,251	225,246

(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

Reconciliation of profit/(loss):

	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Total segments profit/(loss) before tax and finance income/(costs)	218,712	200,995
Finance income	6,589	2,621
Finance expense	(103,885)	(114,972)
(Loss)/gain on derivatives⁽ⁱ⁾	(10,138)	24,251
Profit/(loss) before tax	111,278	112,895

(i) Includes $16.1 million realised losses (2023: $23.3 million realised losses) and $5.9 million unrealised gains (2023: $47.5 million unrealised gains) on derivatives

4. Remeasurements and exceptional items

Period ended 30 June 2024 $'000	Fair value remeasurement(i)	Impairments and write offs(ii)	Other(iii)	Total
Revenue and other operating income	(1,912)	-	-	(1,912)
Cost of sales	7,854	-	-	7,854
Net impairment charge	-	(20,995)	-	(20,995)
Other income	-	-	1,645	1,645
Other expense	(13,764)	-	-	(13,764)
Finance costs	-	-	(28,690)	(28,690)
	(7,822)	(20,995)	(27,045)	(55,862)
Tax on items above	2,956	(4,536)	10,372	8,792
UK Energy Profits Levy	(3,194)	951	(4,520)	(6,763)
	(8,060)	(24,580)	(21,193)	(53,833)

Period ended 30 June 2023 $'000	Fair value remeasurement(i)	Impairments and write offs(ii)	Other(iii)	Total
Revenue and other operating income	37,617	-	-	37,617
Cost of sales	9,921	-	-	9,921
Net impairment charge	-	(96,459)	-	(96,459)
Other income	43,520	-	9,283	52,803
Finance costs	-	-	(29,427)	(29,427)
	91,058	(96,459)	(20,144)	(25,545)
Tax on items above	(35,787)	29,521	9,779	3,513
UK Energy Profits Levy	(32,175)	15,833	10,499	(5,843)
	23,096	(51,105)	134	(27,875)

(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 a gain of $5.9 million (2023: gain of $47.5 million). Other expense relates to the fair value remeasurement of contingent consideration relating to the acquisition of Magnus and associated infrastructure of $13.8 million (note 11) (2023: other income $43.5 million)

(ii) Net impairment charge totalling $21.0 million (note 8) (2023: $96.5 million)

(iii) Other items are made up of the following: other income primarily includes $1.5 million of insurance income related to the Kraken FPSO unplanned downtime in 2023 (2023: recognition of an additional insurance claim debtor related to the PM8/Seligi asset of $4.1 million and reversal of a provision held on acquisition of Golden Eagle asset of: $5.2 million). Finance costs mainly relate to unwinding of discount on contingent consideration on the 75% acquisition of Magnus and associated infrastructure of $28.7 million (note 11) (2023: $29.4 million).

5. Revenue and other operating income

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. Further details are described in the last annual financial statements.

	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Revenue from contracts with customers:
Revenue from crude oil sales	523,065	540,134
Revenue from gas and condensate sales(i)	73,449	213,249
Tariff revenue	1,150	738
Total revenue from contracts with customers	597,664	754,121
Realised (losses)/gains on commodity derivative contracts	(10,664)	(22,168)
Other	932	785
Business performance revenue and other operating income	587,932	732,738
Unrealised (losses)/gains on commodity derivative contracts(ii)	(1,912)	37,617
Total revenue and other operating income	586,020	770,355

(i) Includes onward sale of third-party gas purchases not required for injection activities at Magnus. See Operating costs reconciliation within Non-GAAP measures on page 32

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

6. Income tax

(a) Income tax

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

	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Current UK income tax
Current income tax charge	-	-
Adjustments in respect of current income tax of previous years	-	(33)
Current overseas income tax
Current income tax charge	7,019	11,842
UK Energy Profits Levy
Current year charge	33,530	73,794
Adjustments in respect of current charge of previous years	530	-
Total current income tax	41,079	85,603
Deferred UK income tax
Relating to origination and reversal of temporary differences	68,385	68,549
Adjustments in respect of deferred income tax of previous years	(8,178)	(473)
Deferred overseas income tax
Relating to origination and reversal of temporary differences	1,206	(792)
Deferred UK Energy Profits Levy
Relating to origination and reversal of temporary differences	(23,241)	(18,513)
Adjustments in respect of deferred charge of previous years	1,679	(262)
Total deferred income tax	39,852	48,509
Income tax expense reported in profit or loss	80,930	134,112

(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:

	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Profit/(loss) before tax	111,278	112,895
UK statutory tax rate applying to North Sea oil and gas activities of 40% (2023: 40%)	44,512	45,158
Supplementary corporation tax non-deductible expenditure	2,736	4,330
Non-deductible expenditure(i)	13,047	20,431
Petroleum revenue tax (net of income tax benefit)	(1,704)	-
Tax in respect of non-ring-fence trade	3,960	8,258
Deferred tax asset impairment in respect of non-ring-fence trade	6,416	9,675
UK Energy Profits Levy(ii)	10,289	55,020
Adjustments in respect of prior years	(5,969)	(506)
Overseas tax rate differences	2,576	(613)
Share-based payments	(473)	762
Other differences	5,540	(8,403)
At the effective income tax rate of 73% (2023: 119%)	80,930	134,112

(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 $33.5 million (30 June 2023: $73.8 million charge) and deferred EPL credit of $23.2 million (30 June 2023: $18.5 million credit)

Deferred income tax relates to the following:

	Group balance sheet		Charge/(credit) for the six months ended 30 June recognised in profit or loss
	30 June 2024 $'000	31 December 2023 $'000	2024 $'000	2023 $'000
Deferred tax liability
Accelerated capital allowances	876,976	877,800	(824)	(102,544)
	876,976	877,800
Deferred tax asset
Losses	(654,640)	(695,888)	41,248	68,678
Decommissioning liability	(271,351)	(265,800)	(5,551)	3,603
Other temporary differences	(373,612)	(378,591)	4,979	78,772
	(1,299,603)	(1,340,279)	39,852	48,509
Net deferred tax (assets)	(422,627)	(462,479)
Reflected in the balance sheet as follows:
Deferred tax assets	(479,915)	(540,122)
Deferred tax liabilities	57,288	77,643
Net deferred tax (assets)	(422,627)	(462,479)

Reconciliation of net deferred tax assets/(liabilities)

	30 June 2024 $'000	31 December 2023 $'000
At beginning of period	462,479	539,474
Tax expense during the period recognised in profit or loss	(39,852)	(76,995)
At end of period	422,627	462,479

(d) Tax losses

The Group's deferred tax assets at 30 June 2024 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 $16.1 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 $443.7 million (31 December 2023: $442.1 million) and ring-fence tax losses of $1,163.0 million (31 December 2023: $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 yet 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 $6.3 million (31 December 2023: $8.5 million) remaining unrecognised.

The Group has unused Malaysian income tax losses of $14.3 million (31 December 2023: $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

In June 2023, the UK 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.

In the Autumn Statement on 22 November 2023, the UK Government confirmed that it will bring in legislation for the Energy Security Investment Mechanism which would remove the EPL if both average oil and gas prices fall to, or below, $71.40 per barrel for oil and £0.54 per therm for gas, for two consecutive quarters, and agreed to index link the trigger floor price to the CPI from April 2024. EnQuest does not currently forecast that the floor price will be met for both oil and gas prices and therefore there is currently no impact from this on tax carrying values.

During 2024 to date, further changes were announced in respect of the EPL, with an increased rate, extended duration and treatment of allowances. However, these changes were not substantively enacted at 30 June 2024 and so are not included in the tax balances included in these financial statements. See note 16 for further information.

7. 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.

During the period to 30 June 2024, the Group repurchased 13,938,021 shares which have been classified in the balance sheet as Treasury shares. These Treasury shares have been excluded for the purposes of calculating the basic and diluted earnings per share at 30 June 2024.

Basic and diluted earnings per share are calculated as follows:

	Profit/(loss) after tax				Weighted average number of Ordinary shares			Earnings per share
	Period ended 30 June				Period ended 30 June			Period ended 30 June
	2024 $'000		2023 $'000		2024 million	2023 million	2024 $		2023 $
Basic	30,348	(21,217)		1,895.7		1,843.5		0.016		(0.012)
Dilutive potential of Ordinary shares granted under share-based incentive schemes	-	-		2.5		18.6		-		-
Diluted(i)	30,348	(21,217)		1,898.2		1,862.1		0.016		(0.012)
Basic (excluding remeasurements and exceptional items)	84,181	6,658		1,895.7		1,843.5		0.044		0.004
Diluted (excluding remeasurements and exceptional items)(i)	84,181	6,658		1,898.2		1,862.1		0.044		0.004

(i) Potential ordinary shares granted under share-based incentive schemes are not treated as dilutive when they would decrease a loss per share

8. Property, plant and equipment

	Oil and gas assets $'000	Office furniture, fixtures and fittings $'000	Right-of-use assets $'000	Total $'000
Cost:
At 1 January 2024	9,243,807	68,578	904,994	10,217,379
Additions	150,392	107	4,286	154,785
Change in decommissioning provision	7,280	-	-	7,280
At 30 June 2024	9,401,479	68,685	909,280	10,379,444
Accumulated depreciation, depletion and impairment:
At 1 January 2024	7,364,063	59,314	497,262	7,920,639
Charge for the period	111,977	1,407	26,439	139,823
Net impairment charge/(reversal)	38,701	-	(17,706)	20,995
At 30 June 2024	7,514,741	60,721	505,995	8,081,457
Net carrying amount:
At 30 June 2024	1,886,738	7,964	403,285	2,297,987
At 31 December 2023	1,879,744	9,264	407,732	2,296,740
At 30 June 2023	1,871,225	10,036	406,950	2,288,211

Impairments

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

	Net impairment (charge) / reversal		Recoverable amount(i)
	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000	Period ended 30 June 2024 $'000	Year ended 31 December 2023 $'000
North Sea	(20,995)	(96,459)	1,286,459	1,323,009
Net pre-tax impairment charge	(20,995)	(96,459)

(i) Recoverable amount has been determined on a fair value less costs of disposal basis. 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

The 2024 net impairment charge of $21.0 million relates to producing assets in the UK North Sea. Impairment charges/reversals were primarily driven by changes in production and cost profiles, including higher decommissioning cost estimates (see note 12) and an extension of the UK Energy Profits Levy to 31 March 2029 offset partially by an increase in EnQuest's future oil price assumptions and a lower discount rate of 10.5%.

The 2023 net impairment charge of $96.5 million relates to producing assets in the UK North Sea. These were primarily driven by a decrease in EnQuest's future price assumptions.

Sensitivity analyses

Management tested the impact of a change in cash flows in FVLCD impairment testing arising from a 10.0% reduction in price assumptions.

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 $213.0 million, which is approximately 9% of the net book value of property, plant and equipment as at 30 June 2024.

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 incorporate consequential changes that may arise, such as reduction in costs and 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 1.0% change in the discount rate of 10.5% used for FVLCD impairment testing of oil and gas properties which is considered a reasonably possible change given the prevailing macroeconomic conditions. If the discount rate was 1.0% higher across all tests performed, the net impairment recognised in first half of 2024 would have been approximately $49.6 million higher. If the discount rate was 1.0% lower, the net impairment charge recognised would have been approximately $54.2 million lower.

See note 16 for details on the impact on impairment from the changes to EPL announced on 29 July 2024.

9. Loans and borrowings

	30 June 2024 $'000	31 December 2023 $'000
Loans	181,108	311,231
Bonds	471,147	463,945
	652,255	775,176

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

	30 June 2024			31 December 2023
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
RBL facility⁽ⁱ⁾	-	-	-	140,000	(4,920)	135,080
Term Loan Facility	150,000	(3,125)	146,875	150,000	(3,633)	146,367
SVT Working Capital facility	34,775	-	34,775	29,784	-	29,794
High yield bond 11.625%	305,000	(9,304)	295,696	305,000	(10,724)	294,276
Retail bond 9.00%	168,565	-	168,565	169,669	-	169,669
Accrued interest⁽ⁱⁱ⁾	6,344	-	6,344	-	-	-
Total borrowings	664,684	(12,429)	652,255	794,453	(19,277)	775,176
Due within one year			40,105			27,364
Due after more than one year			612,150			747,812
Total borrowings			652,255			775,176

(i) During the period to 30 June 2024, the Group repaid the full $140.0 million of the outstanding principal, with capitalised fees reclassed in the current period to trade and other receivables to better reflect the variable nature of the facility (comparative information has not been restated as it is not material). 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. At 30 June 2024, after allowing for letter of credit utilisation of $54.6 million, $246.2 million remained available for drawdown under the facility.

(ii) Accrued interest on borrowings has been reclassed in the current period to better reflect the total borrowings balance (comparative information has not been restated as it is not material). Accrued interest includes bond interest accruals of $6.9 million.

10. Other financial assets and financial liabilities

(a) Summary as at 30 June 2024

	30 June 2024		31 December 2023
	Assets $'000	Liabilities $'000	Assets $'000	Liabilities $'000
Fair value through profit or loss:
Derivative commodity contracts	1,161	16,591	4,499	18,418
Derivative foreign exchange contracts	859	-	-	-
Derivative UKA contracts	-	1,266	-	8,261
Amortised cost:
Other receivables (Vendor financing facility) ⁽ⁱ⁾	-	-	108,827	-
Total current	2,020	17,857	113,326	26,679
Fair value through profit or loss:
Quoted equity shares	6	-	6	-
Amortised cost:
Other receivables (Vendor financing facility)	37,448	-	36,276	-
Total non-current	37,454	-	36,282	-
Total other financial assets and liabilities	39,474	17,857	149,608	26,679

(i) Repayment 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:

Period ended 30 June 2024	Revenue and other operating income		Cost of sales
Period ended 30 June 2024	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	(9,285)	1,312	-	-
Commodity swaps	858	(3,224)	-	-
Commodity futures	(2,237)	-	-	-
Foreign exchange contracts	-	-	583	859
UKA contracts	-	-	(5,999)	6,995
	(10,664)	(1,912)	(5,416)	7,854

Period ended 30 June 2023	Revenue and other operating income		Cost of sales
Period ended 30 June 2023	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	(26,375)	31,531	-	-
Commodity swaps	4,786	6,086	-	-
Commodity futures	(579)	-	-	-
Foreign exchange contracts	-	-	1,737	9,648
UKA contracts	-	-	(2,856)	273
	(22,168)	37,617	(1,119)	9,921

30 June 2024	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		1,161	-	-	1,161	-
Forward foreign currency contracts		859	-	-	859	-
Other financial assets at FVPL						-
Quoted equity shares		6	-	6	-	-
Total financial assets measured at fair value		2,026	-	6	2,020	-
Financial assets measured at amortised cost:
Vendor financing facility		37,448	37,448	-	-	-
Total financial assets measured at amortised cost ⁽ⁱ⁾		37,448	37,448	-	-	-
Liabilities measured at fair value:
Derivative financial liabilities at FVPL
Oil commodity derivative contracts		16,591	-	-	16,591	-
Forward UKA contracts		1,266	-	-	1,266	-
Other financial liabilities measured at FVPL
Contingent consideration		501,722	-	-	-	501,722
Total liabilities measured at fair value		519,579	-	-	17,857	501,722
Liabilities measured at amortised cost for which fair values are disclosed below:
Interest-bearing loans and borrowings ⁽ⁱ⁾	9	184,775	184,775	-	-	-
Retail bond 9.00%	9	162,539	-	162,539	-	-
High yield bond 11.625%	9	309,752	-	309,752	-	-
Total liabilities measured at amortised cost for which fair values are disclosed ⁽ⁱⁱ⁾		657,066	184,775	472,291	-	-
(i) Amortised cost is a reasonable approximation of the fair value (ii) Excludes related fees
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 derivative contracts		4,499	-	-	4,499	-
Other financial assets 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		145,103	145,103	-	-	-
Total financial assets measured at amortised cost ⁽ⁱ⁾		145,103	145,103	-	-	-
Liabilities measured at fair value:
Derivative financial liabilities at FVPL
Oil commodity derivative contracts		18,418	-	-	18,418	-
Forward UKA Contracts		8,261	-	-	8,261	-
Other financial liabilities measured at FVPL
Contingent consideration		507,796	-	-	-	507,796
Total liabilities measured at fair value		534,475	-	-	26,679	507,796
Liabilities measured at amortised cost for which fair values are disclosed below:
Interest-bearing loans and borrowings⁽ⁱ⁾	9	319,784	319,784	-	-	-
Retail bond 9.00%	9	158,683	-	158,683	-	-
High yield bond 11.625%	9	292,419	-	292,419	-	-
Total liabilities measured at amortised cost for which fair values are disclosed ⁽ⁱⁱ⁾		770,886	319,784	451,102	-	-

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

(ii) Excludes related fees

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 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;

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 11. There have been no transfers between Level 1 and Level 2 during the period (2023: no transfers).

For the financial assets and liabilities measured at amortised costs but for which fair value disclosures are required, the fair value of the bonds classified as Level 1 was derived from quoted prices for each financial instrument. 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 14.

11. Contingent consideration

	Magnus 75% $'000	Magnus decommissioning-linked liability $'000	Total $'000
At 31 December 2023	488,007	19,789	507,796
Change in fair value	13,331	433	13,764
Unwinding of discount	27,572	1,118	28,690
Utilisation	(48,118)	(410)	(48,528)
At 30 June 2024	480,792	20,930	501,722
Classified as:
Current	50,759	3,337	54,096
Non-current	430,033	17,593	447,626
	480,792	20,930	501,722

75% Magnus acquisition contingent consideration

The contingent consideration was fair valued at 30 June 2024, which resulted in an increase in fair value of $13.3 million reflecting a change in the Group's oil price assumptions partially offset by production profile changes (30 June 2023: decrease of $41.9 million reflecting a change in the Group's near term oil price assumptions and a 1.3% increase in the discount rate to 11.3%). The fair value accounting effect and finance costs of $27.6 million (30 June 2023: $28.3 million) on the contingent consideration were recognised through remeasurements and exceptional items in the Group income statement. Within the statement of cash flows, the profit share element of the payment, $48.1 million (30 June 2023: $38.2), is disclosed separately under investing activities. At 30 June 2024, the contingent consideration was $480.8 million (31 December 2023: $488.0 million). At 30 June 2024, the contingent profit-sharing arrangement cap of $1 billion is forecast to be met in the present value calculations (31 December 2023: cap was forecast to be met).

Management has considered alternative scenarios to assess the valuation of the contingent consideration including, but not limited to, the key accounting estimate relating to discount rate, the oil price and the interrelationship with production and the profit-share arrangement. A 1.0% reduction in the discount rate applied, which is considered a reasonably possible change given the prevailing macroeconomic conditions, would increase contingent consideration by $17.9 million. A 1.0% increase would decrease contingent consideration by $16.8 million. At 30 June 2024, the contingent profit-sharing cap of $1.0 billion is forecast to be met in the present value calculations (31 December 2023: cap was forecast to be met), therefore 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 $74.4 million to the contingent consideration (31 December 2023: reduction of $83.3 million).

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 30 June 2024, the amount due to bp, calculated on an after-tax basis by reference to 30% of bp's decommissioning costs on Magnus, was $20.9 million (31 December 2023: $19.8 million).

12. Provisions

	Decommissioning provision $'000	Thistle decommissioning provision $'000	Other provisions $'000	Total $'000
At 31 December 2023	755,762	25,355	14,180	795,297
Additions	1,436	-	42	1,478
Changes in estimates	12,254	(1,483)	-	10,771
Unwinding of discount	13,213	444	-	13,657
Utilisation	(20,782)	(3,519)	(212)	(24,513)
Foreign exchange	-	(5)	(237)	(242)
At 30 June 2024	761,883	20,792	13,773	796,448
Classified as:
Current	48,142	8,135	13,773	70,050
Non-current	713,741	12,657	-	726,398
	761,883	20,792	13,773	796,448

Decommissioning provision

The Group's total provision represents the present value of decommissioning costs which are expected to be incurred up to 2050, assuming no further development of the Group's assets. The Group's decommissioning provision has increased by $6.1 million in the period. This is primarily reflecting higher cost estimates of $72.5 million including movements in foreign exchange rates, offset partly by the ongoing decommissioning programmes and an increase in the discount rate of 1.0% to 4.5% resulting in a decrease of $59.3 million. At 30 June 2024, an estimated $295.2 million is expected to be utilised between one and five years (31 December 2023: $175.7 million), $275.1 million within six to ten years (31 December 2023: $355.6 million), and the remainder in later periods.

The Group enters into surety bonds principally to provide security for its decommissioning obligations. At 30 June 2024, the Group held surety bonds totalling $279.4 million (31 December 2023: $250.4 million).

Changes in assumptions, including cost reduction factors, in relation to the Group's provisions could result in a material change in their carrying amounts within the next financial year. A 1.0% 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 $60.1 million. The pre-tax impact on the Group income statement would be a charge of approximately $14.3 million, reflecting the change in estimates for assets which have already ceased production.

Thistle decommissioning provision

At 30 June 2024, the amount due to bp by reference to 7.5% of bp's decommissioning costs on Thistle and Deveron was $20.8 million (31 December 2023: $25.4 million), with the reduction mainly reflecting the utilisation in the period and a reduction in the fair value predominantly due to an increase in the discount rate assumption. Unwinding of discount of $0.4 million is included within finance income for the period ended 30 June 2024 (30 June 2023: $0.6 million).

Other provisions

During 2021, the Group recognised $8.2 million in relation to a dispute with a third-party contractor. The Group expects the dispute to be settled in 2024. At 30 June 2024, the provision decreased as a result of utilisation and favourable exchange rate movements to $8.7 million (31 December 2023: $9.1 million).

13. Commitments and contingencies

Capital commitments

At 30 June 2024, the Group had commitments for future capital expenditure amounting to $42.7 million (31 December 2023: $43.8 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 an operated joint venture, the amount represents the Group's net share of the commitment.

Other commitments

In the normal course of business, the Group will obtain surety bonds, letters of credit and guarantees. At 30 June 2024, the Group held surety bonds totalling $279.4 million (31 December 2023: $250.4 million) to provide security for its decommissioning obligations.

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's financial position or profitability, nor, so far as the Group is aware, are any such proceedings pending or threatened.

14. Cash flow information

Cash generated from operations

	Notes	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Profit/(loss) before tax		111,278	112,895
Depreciation	8	3,091	3,039
Depletion	8	136,732	147,858
Net impairment charge to oil and gas assets	8	20,995	96,459
Net (write back)/disposal of inventory		(5,240)	2,048
Other non-cash income		(1,645)	(4,023)
Share-based payment charge		895	1,353
Change in contingent consideration	11	42,454	(12,430)
Change in provisions		18,628	15,303
Option premium recognition		-	10,567
Unrealised loss/(gain) on commodity financial instruments		1,912	(37,617)
Unrealised (gain) on other financial instruments		(7,854)	(9,921)
Unrealised exchange (gain)/loss		(8,659)	16,645
Net finance expense		54,949	70,234
Operating cash flow before working capital changes		367,536	412,410
Decrease in trade and other receivables		5,415	16,086
(Increase) in inventories		(1,536)	(6,771)
(Decrease) in trade and other payables		(2,543)	(51,304)
Cash generated from operations		368,872	370,421

Changes in liabilities arising from financing activities

	Loans and borrowings $'000	Bonds $'000	Lease liabilities $'000	Total $'000
At 31 December 2023	(311,210)	(471,019)	(422,174)	(1,204,403)
Cash movements:
Repayments of loans and borrowings	154,528	-	-	154,528
Proceeds from loans and borrowings	(19,735)	-	-	(19,735)
Payment of lease liabilities	-	-	85,020	85,020
Cash interest paid in period	11,932	25,359	-	37,291
Non-cash movements:
Additions	-	-	(4,286)	(4,286)
Interest/finance charge payable	(11,411)	(25,232)	(16,642)	(53,285)
Fee amortisation	(1,206)	(1,551)	-	(2,757)
Foreign exchange and other non-cash movements	(4,006)	1,296	493	(2,217)
At 30 June 2024	(181,108)	(471,147)	(357,589)	(1,009,844)

Reconciliation of carrying value

	Loans and borrowings $'000	Bonds $'000	Lease liabilities $'000	Total $'000
Principal	184,775	473,565	357,589	1,015,929
Unamortised fees	(3,125)	(9,304)	-	(12,429)
Accrued interest	(542)	6,886	-	6,344
At 30 June 2024	181,108	471,147	357,589	1,009,844

15. Distributions

In April 2024, the Board of Directors agreed an up to $15.0 million share buy back to be executed during 2024 which was 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. At 30 June 2024, 13,938,021 shares had been repurchased at a cost of $2.5 million and which have been classed in the balance sheet as Treasury shares.

16. Subsequent events

On 29th July 2024, the UK government announced changes to the EPL. From 1 November 2024 the rate of EPL will be increased to 38% (currently 35%) and the period to which EPL applies will be extended to 31 March 2030 (currently 31 March 2028). The EPL investment allowance is being abolished and the relief currently available for capital expenditure will likely be reduced. Further details of the changes are expected to be finalised in the Budget scheduled to take place on 30 October 2024. These measures have not been enacted at the balance sheet date therefore there is no impact on the 30 June 2024 balance sheet. As the full details have not been announced it is not yet possible to calculate the full potential future impact on the balance sheet, but the impact of the increase in headline tax rate, removal of the EPL investment allowance and extension to 2030 are expected to result in an additional tax liability of approximately $102.5 million across the period in which EPL will be levied. These changes to the EPL would also reduce the carrying value of the Group's assets by approximately $50.3 million.

In late August 2024, the Malaysian Court of Appeal issued a judgement in relation to a dispute with a third party supplier that funds held in escrow, and reflected in the Group's restricted cash balance at 30 June 2024, should be released to the third party supplier pending resolution of the final arbitration decision. Should the final arbitration decision find in the favour of EnQuest, EnQuest would seek reimbursement of any funds transferred.

Statement of Directors' Responsibilities

We confirm that to the best of our knowledge:

a) the condensed set of financial statements has been prepared in accordance with the UK-adopted IAS 34 'Interim Financial Reporting';

b) the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of important events and their impact during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and

c) the interim management report includes a fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein).

A list of current Directors is maintained on the EnQuest PLC website which can be found at www.enquest.com.

By the order of the Board

Jonathan Copus

Chief Financial Officer

4 September 2024

Independent review report to EnQuest PLC

Conclusion

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2024 which comprises the Group Income Statement, the Group Balance Sheet, the Group Statement of Changes in Equity, the Group Statement of Cash Flows and related notes 1 to 16.

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2024 is not prepared, in all material respects, in accordance with United Kingdom adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Basis for Conclusion

We conducted our review in accordance with International Standard on Review Engagements (UK) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council for use in the United Kingdom (ISRE (UK) 2410). A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

As disclosed in note 2, the annual financial statements of the group are prepared in accordance with United Kingdom adopted international accounting standards. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with United Kingdom adopted International Accounting Standard 34, "Interim Financial Reporting".

Conclusion Relating to Going Concern

Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for Conclusion section of this report, nothing has come to our attention to suggest that the directors have inappropriately adopted the going concern basis of accounting or that the directors have identified material uncertainties relating to going concern that are not appropriately disclosed.

This conclusion is based on the review procedures performed in accordance with ISRE (UK) 2410; however future events or conditions may cause the entity to cease to continue as a going concern.

Responsibilities of the directors

The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

In preparing the half-yearly financial report, the directors are responsible for assessing the group's ability to continue as a going concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the company or to cease operations, or have no realistic alternative but to do so.

Auditor's Responsibilities for the review of the financial information

In reviewing the half-yearly financial report, we are responsible for expressing to the company a conclusion on the condensed set of financial statement in the half-yearly financial report. Our conclusion, including our Conclusion Relating to Going Concern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.

Use of our report

This report is made solely to the company in accordance with ISRE (UK) 2410. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.

Deloitte LLP

Statutory Auditor

London, United Kingdom

4 September 2024

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 annual consolidated financial statements, published in April 2024, on page 193.

Business performance net profit attributable to EnQuest PLC shareholders	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Reported net (loss)/profit (A)	30,348	(21,217)
Adjustments - remeasurements and exceptional items:
Unrealised gains/(losses) on derivative contracts (note 10b)	5,942	47,538
Net impairment (charge)/reversal to oil and gas assets (notes 4 and 8)	(20,995)	(96,459)
Finance costs on Magnus on contingent consideration (note 11)	(28,690)	(29,427)
Change in fair value of Magnus contingent consideration (note 11)	(13,764)	43,520
Other exceptional income (note 4)	1,645	9,283
Pre-tax remeasurements and exceptional items (B)	(55,862)	(25,545)
Tax on remeasurements and exceptional items (note 4) (C)	2,029	(2,330)
Post-tax remeasurements and exceptional items (D = B + C)	(53,833)	(27,875)
Business performance net profit attributable to EnQuest PLC shareholders (A - D)	84,181	6,658

Adjusted EBITDA is a measure of profitability. It provides a metric to show earnings before the influence of accounting (i.e. depletion and depreciation) and financial deductions (i.e. borrowing interest). For the Group, this is a useful metric as a measure to evaluate the Group's underlying operating performance and is a component of a covenant measure under the Group's RBL facility 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 service and 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) from operations before tax and finance income/(costs).

Adjusted EBITDA	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Reported profit/(loss) from operations before tax and finance income/(costs)	208,574	225,246
Adjustments:
Remeasurements and exceptional items (note 4)	27,172	(3,882)
Depletion and depreciation (note 8)	139,823	150,897
Inventory revaluation	(5,240)	2,048
Change in provision	4,928	7,247
Net foreign exchange (gain)/loss	(7,753)	17,683
Adjusted EBITDA (E)	367,504	399,239

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 assessment, see page 10.

Total cash and available facilities	Period ended 30 June 2024 $'000	Year ended 31 December 2023 $'000
Available cash	327,848	313,028
Restricted cash	9,471	544
Total cash and cash equivalents (F)	337,319	313,572

Available credit facilities	433,250	518,794
Credit facilities - drawn down (note 9)	(150,000)	(290,000)
Letter of credit	(54,580)	(43,545)
Available undrawn facility (G)	228,670	185,249
Total cash and available facilities (F + G)	565,989	498,821

Net debt is a liquidity measure that shows how much debt a company has on its balance sheet compared to its cash and cash equivalents. With
de-leveraging a strategic priority, the Group believes this is a useful metric to demonstrate progress in this regard. It is also an important reference point for the Group's going concern assessment, see page 10. 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	Period ended 30 June 2024 $'000	Year ended 31 December 2023 $'000
Borrowings (note 9):
RBL facility	-	135,080
Term Loan facility	146,875	146,367
SVT Working Capital facility	34,775	29,784
High yield bond	295,696	294,276
Retail bond	168,565	169,669
Accrued interest	6,344	-
Borrowings (H)	652,255	775,176
Non-cash accounting adjustments (note 9):
Unamortised fees on loans and borrowings	3,125	8,553
Unamortised fees on bonds	9,304	10,724
Accrued interest	(6,344)	-
Non-cash accounting adjustments (I)	6,085	19,277
Debt (H + I ) (J)	658,340	794,453
Less: Cash and cash equivalents (F)	337,319	313,572
EnQuest net debt (J - F) (K)	321,021	480,881

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	Period ended 30 June 2024 $'000	Year ended 31 December 2023 $'000
EnQuest net debt (K)	321,021	480,881
Adjusted EBITDA (last 12 months) (E)	792,931	824,666
EnQuest net debt/adjusted EBITDA (K/E)	0.4	0.6

Cash capital expense (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 programmes and the focus on the Group's liquidity position and ability to reduce its debt.

Cash capital and decommissioning expense	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Reported net cash flows (used in)/from investing activities	(30,468)	(115,865)
Adjustments:
Payment of Magnus contingent consideration - Profit share	48,118	38,229
Purchase of other intangible assets	321	-
Proceeds from vendor financing facility receipt	(107,518)	-
Proceeds from Bressay farm down	(1,263)	-
Interest received	(4,181)	(2,398)
Cash capital expense	(94,991)	(80,034)
Decommissioning spend	(31,516)	(29,333)
Cash capital and decommissioning expense	(126,507)	(109,367)

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

The 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	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Net cash flows from/(used in) operating activities	323,739	371,046
Net cash flows from/(used in) investing activities	(30,468)	(115,865)
Net cash flows from/(used in) financing activities	(266,267)	(273,279)
Adjustments:
Proceeds of loans and borrowings	(19,735)	(21,468)
Proceeds from vendor financing facility receipt	(107,518)	-
Proceeds from Bressay farm down	(1,263)	-
Repayment of loans and borrowings	154,528	179,591
Payment for repurchase of shares	2,479	-
Free cash flow	55,495	140,025

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 from sales	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Revenue from crude oil sales (note 5) (L)	523,065	540,134
Revenue from gas and condensate sales (note 5) (M)	73,449	213,249
Realised (losses)/gains on oil derivative contracts (note 5) (N)	(10,664)	(22,168)
Barrels equivalent sales	Period ended 30 June 2024 kboe	Period ended 30 June 2023 kboe
Sales of crude oil (P)	6,145	6,833
Sales of gas and condensate(i)	1,235	2,404
Total sales (Q)	7,380	9,237

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

Average realised prices

Period ended

30 June

2024

$/Boe

Period ended

30 June

2023

$/Boe

Average realised oil price, excluding hedging (L/P)

85.1

79.0

Average realised oil price, including hedging ((L + N)/P)

83.4

75.8

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	Period ended 30 June 2024 $'000	Period ended 30 June 2023 $'000
Reported cost of sales	352,310	483,219
Adjustments:
Remeasurements and exceptional items	7,854	9,921
Depletion of oil and gas assets	(136,732)	(147,858)
Credit/(charge) relating to the Group's lifting position and inventory	22,807	15,342
Other cost of sales(i)	(63,222)	(197,934)
Operating costs	183,017	162,690
Less realised loss/(gain) on derivative contracts (R)	5,416	1,119
Operating costs directly attributable to production	177,601	161,571
Comprising of:
Production costs (S)	143,618	145,465
Tariff and transportation expenses (T)	33,983	16,106
Operating costs directly attributable to production	177,601	161,571

(i) Includes $52.4 million (2023: $186.3 million) of purchases and associated costs of third-party gas not required for injection activities at Magnus which is sold on

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 it's risk to market price movements.

Barrels equivalent produced

Period ended

30 June

2024

kboe

Period ended

30 June

2023

kboe

Total produced (working interest) (U) (i)

7,784

8,232

(i) Production figure includes 1,614 Boepd associated with Seligi gas (2023: 660 Boepd)

Unit opex	Period ended 30 June 2024 $/Boe	Period ended 30 June 2023 $/Boe
Production costs (S/U)	18.4	17.7
Tariff and transportation expenses (T/U)	4.4	2.0
Total unit opex ((S + T)/U)	22.8	19.7
Realised loss/(gain)/ on derivative contracts (R/U)	0.7	0.1
Total unit opex including hedging ((R + S+ T)/U)	23.5	19.8

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