Half-year Results

RNS Number : 4761K

EnQuest PLC

02 September 2021

EnQuest PLC

Results for the six months ended 30 June 2021

2 September 2021

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

Comparative figures for the income statement relate to the period ended 30 June 2020 and the Balance Sheet as at 31 December 2020. Alternative performance measures are reconciled within the 'Glossary - Non-GAAP measures' at the end of the Financial Statements.

EnQuest Chief Executive, Amjad Bseisu, said:

" The Group delivered strong free cash flow in the first half which reduced net debt. Performance at Kraken has been good with the FPSO performing well, while production at PM8/Seligi has been better than expected as a result of the acceleration of initial restoration activities following the riser detachment. Production at Magnus has been impacted by topside related well performance but our production enhancement programme has partially recovered the well potential and we expect further recovery over the remainder of the year. We remain focused on improving production across our existing portfolio.

"The Golden Eagle acquisition remains on track to complete around the end of September and will add production, reserves and cash flow to the Group, while the Bressay and Bentley acquisitions, offer further long-term potential development opportunities."

H1 2021 performance

· Group net production averaged 46,187 Boepd (2020: 66,055 Boepd)

· Kraken production of 23,690 Boepd (33,603 Boepd gross) was in line with the Group's guidance reflecting strong production and water injection efficiency and a good performance from the Floating Production, Storage and Offloading vessel ('FPSO')

· Improved production at PM8/Seligi as a result of the acceleration of initial production recovery activities following the riser detachment in late 2020

· Lower production at Magnus reflected the slower execution and an increase in scope of the well intervention programme, an unplanned third-party outage, power related failures and natural declines

· Revenue and other operating income of $518.3 million (2020: $450.0 million) and EBITDA of $345.4 million (2020: $320.8 million) reflects materially higher oil prices, partially offset by lower production

· Operating costs decreased to $153.0 million (2020: $174.3 million) primarily reflecting lower tariff expenditure

· Cash generated from operations of $287.9 million (2020: $282.6 million); cash expenditures of $54.6 million (2020: $108.5 million)

· Strong free cash flow generation of $141.5 million (2020: $86.8 million) reflecting materially lower cash expenditures

End June net debt reduced by $96.5 million from year end

· At 30 June 2021, net debt reduced to $1,183.2 million (end 2020: $1,279.7 million) reflecting strong free cash flow generation. Total cash and available facilities were $303.4 million (end 2020: $284.1 million)

· Signed a new senior secured borrowing base debt facility (the 'RBL') of $600 million with an additional amount of $150 million for letters of credit for up to seven years

Significant business development

· Agreed to acquire Suncor Energy UK Limited's 26.69% non-operated interest in the producing Golden Eagle area for an initial consideration of $325.0 million with completion expected around the end of September

· Signed a Share Purchase agreement ('SPA') with Whalsay Energy Holdings Limited to purchase its 100.0% equity interest in the P1078 licence containing the proven Bentley heavy-oil discovery. Bentley offers long-term potential development opportunities and other synergies, with the transaction completed in July

Guidance and outlook

· 2021 average net Group production is expected to be at the lower end of the guidance range of 46,000 Boepd and 52,000 Boepd. This reflects expected performances at Magnus, the Greater Kittiwake Area and PM8/Seligi over the course of the second half of the year. Kraken gross production is expected to be between 30,000 Boepd and 35,000 Boepd (21,150 Boepd to 24,675 Boepd net)

· Operating costs are expected to be approximately $300 million, reflecting lower lease charter credits driven by higher uptime at Kraken, additional production enhancement scopes and topside maintenance activities at Magnus, higher diesel costs and sterling strength

· Combined cash capital and abandonment expenditure, excluding costs associated with the PM8/Seligi riser repair, is expected to be broadly around $120 million

· EnQuest has hedged a total of c.11 MMbbls for full year 2021 predominantly using costless collars, with an average floor price of c.$59/bbl and an average ceiling price of c.$69/bbl, with c.6 MMbbls hedged with an average floor of c.$62/bbl and ceiling price of c.$73/bbl in the second half of 2021. For 2022, EnQuest has hedged a total of c.6 MMbbls using similar structures, with an average floor price of c.$61/bbl and an average ceiling price of c.$75/bbl. For 2023, the Group has hedged a total of approximately c.1 MMbbls with an average floor price of c.$55/bbl and an average ceiling price of c.$73/bbl

Production and financial information

Business performance measures	For the period to 30 June 2021	For the period to 30 June 2020	Change %
Production (Boepd)	46,187	66,055	(30.1)
Revenue and other operating income ($m)^1,2	518.3	450.0	15.2
Realised oil price ($/bbl)^1,3	62.8	43.6	44.0
Average unit operating costs ($/Boe)³	19.3	14.4	34.0
EBITDA ($m)³	345.4	320.8	7.7
Cash expenditures ($m)	54.6	108.5	(49.7)
Capital³	15.9	101.4	(84.3)
Abandonment	38.7	7.1	445.1
Free cash flow ($m)³	141.5	86.8	63.0
	30 June 2021	31 December 2020
Net (debt)/cash ($m)³	(1,183.2)	(1,279.7)	(7.5)

Statutory measures	For the period to 30 June 2021	For the period to 30 June 2020	Change %
Reported revenue and other operating income ($m)^2,4	481.3	438.7	9.7
Reported gross profit ($m)	148.1	18.7	692.0
Reported profit/(loss) after tax ($m)²	(56.4)	(472.4)	88.1
Reported basic earnings/(loss) per share (cents)²	(3.4)	(28.6)	88.1
Cash generated from operations ($m)²	287.9	282.6	1.9
Net increase/(decrease) in cash and cash equivalents	53.3	(32.1)	-

Notes:

¹ Including realised losses of $32.9 million (2020: realised gains of $35.2 million) associated with EnQuest's oil price hedges

² Comparative information for 2020 has been restated. See Note 2 Basis of preparation - Restatements

³ See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 31. Note, during the second half of 2020, the Group's definition of EBITDA was updated. Comparative information for 2020 has been updated to reflect the changes, which are outlined in the Glossary.

Note, EnQuest defines net debt as excluding finance lease liabilities

⁴ Including net realised and unrealised losses of $69.9 million (2020: net realised and unrealised gains of $23.9 million) associated with EnQuest's oil price hedges

Summary financial review

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

Revenue and other operating income for the six months ended 30 June 2021 was $518.3 million, 15.2% higher than the same period in 2020 ($450.0 million), reflecting the materially higher oil prices offset by a reduction in production. Revenue is predominantly derived from crude oil sales, which for the first half of 2021 totalled $490.5 million, 30.6% higher than in the same period of 2020 ($375.5 million). Revenue from the sale of condensate and gas in the period was $57.9 million (2020: $27.6 million), primarily reflecting higher market prices for condensate and gas. Gas revenue mainly relates to the onward sale of third-party gas purchases not required for injection activities at Magnus.

The Group's commodity hedges and other oil derivatives contributed $32.9 million of realised losses (2020: gains of $35.2 million), as a result of the timing at which the hedges were entered into. The Group's average realised oil price excluding the impact of hedging was $67.3/bbl for the six months ended 30 June 2021, compared to $39.9/bbl received during the first half of 2020. The Group's average realised oil price including the impact of hedging was $62.8/bbl in the first half of 2021, 44.0% higher than during the first half of 2020 ($43.6/bbl).

Total cost of sales were $333.3 million for the six months ended 30 June 2021, 18.9% lower than in same period of 2020 ($410.9 million).

Operating costs decreased by $21.3 million, primarily reflecting low tariff and transportation costs due to lower production for the first half of 2021, with production costs broadly flat year on year as lower costs following asset cessation of production ('CoP') have been offset by remediation costs at Magnus and lower lease charter credits reflecting higher uptime at Kraken driven by the continued strong performance of the FPSO. Unit operating costs increased by 34.0% to $19.3/Boe (2020: $14.4/Boe) as a result of lower production.

Total cost of sales included non-cash depletion expense of $153.1 million, 38.4% lower than in the same period in 2020 ($248.4 million), mainly reflecting the decisions to cease production at Dons and Alma/Galia and a decrease in the unit-of-production rate arising from impairments booked in the period ended 31 December 2020.

Also within cost of sales, the credit relating to the Group's lifting position and hydrocarbon inventory for the six months ended 30 June 2021 was $26.1 million (2020: credit of $48.5 million). This reflects an increase in the net underlift position from $3.0 million at 31 December 2020 to $32.0 million at 30 June 2021.

Other cost of sales, which forms part of the total cost of sales balance, of $53.3 million were higher than the same period in 2020 ($36.7 million), reflecting the higher cost of Magnus-related third-party gas purchases following the increase in the market price for gas.

EBITDA for the six months ended 30 June 2021 was $345.4 million, up 7.7% compared to the same period in 2020 ($320.8 million), driven by higher revenue.

The tax credit for the six months ended 30 June 2021 was $19.4 million (2020: $71.5 million tax credit).

Remeasurements and exceptional items were a net post-tax loss of $164.6 million for the six months ended 30 June 2021 (2020 restated: loss of $ 478.7 million). Revenue included unrealised losses of $37.0 million in respect of the mark-to-market movement on the Group's commodity contracts (2020: unrealised losses of $ 11.3 million). Other remeasurements and exceptional items includes a $27.5 million gain in relation to the fair value recalculation of the Magnus contingent consideration reflecting a change in the payment profile. The Group recognised a non-cash deferred tax charge of $139.5 million (2020 restated: $286.0 million see Note 2 Basis of preparation - Restatements), following a reassessment of deferred tax balances reflecting revisions to forecast assumptions.

The Group's reported cash generated from operations for the six months ended 30 June 2021 was $287.9 million (2020: $282.6 million). Free cash flow for the six months ended 30 June 2021 was $141.5 million (2020: $86.8 million) reflecting the materially lower cash capital expenditure in 2021, partially offset by higher decommissioning spend.

In January 2021, EnQuest made a voluntary early repayment of $25.0 million on the Multi-currency revolving credit facility ('RCF'). The strong production performance at Kraken combined with higher oil prices enabled the full repayment of the $67.7 million outstanding balance on the Sculptor Capital facility in the period to 30 June 2021.

Net debt at 30 June 2021 was $1,183.2 million, a decrease of 7.5% compared to 31 December 2020 ($1,279.7 million). This includes $244.4 million of payment in kind interest ("PIK interest") that has been capitalised to the principal of the facility and bonds pursuant to the terms of the Group's November 2016 refinancing (31 December 2020: $205.8 million).

In July 2021, $360.0 million was drawn down from the Group's new senior secured borrowing base debt facility. The proceeds were used to repay the entire outstanding balance on the RCF, which at the time of repayment was $354.5 million, including PIK and accrued interest. In addition, $58.7 million, representing the full amount of the outstanding principal and interest on the Magnus vendor loan, was repaid.

Operating review

Production details

Average daily production on a net working interest basis	For the period to 30 June 2021	For the period to 30 June 2020
	(Boepd)	(Boepd)
UK Upstream
- Magnus	13,847	18,806
- Kraken	23,690	27,472
- Other Upstream¹	3,504	7,700
UK Upstream	41,041	53,978
UK Decommissioning ²	337	3,771
Total UK	41,378	57,749
Total Malaysia	4,809	8,306
Total EnQuest	46,187	66,055

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

² UK Decommissioning: Heather/Broom, Thistle/Deveron, the Dons and Alma/Galia

UK Upstream operations

Magnus

Production of 13,847 Boepd was 26.4% lower than in 2020, primarily reflecting slower execution and an increase in scope of the well intervention programme, combined with an unplanned third-party outage, power related failures and natural declines associated with the new wells that were brought onstream in early 2020. Given the challenges that have been presented during the first half of the year, a proactive production enhancement programme was initiated comprising various well intervention techniques, including a coiled tubing campaign, alongside additional topside maintenance activities. Since June, three wells have been returned to service and production performance has improved. The coiled tubing campaign is expected to continue during the second half of the year, with the Group expecting production performance to improve further in the fourth quarter, with a two-well drilling campaign anticipated in 2022.

Kraken

Average production of 23,690 Boepd (33,603 Boepd gross) remains in line with the Group's 2021 guidance, which remains unchanged. The reduction from 2020 reflects the impacts of a riser tether repair and natural declines. Production and water injection efficiency remained strong at 90% and 92%, respectively, and the FPSO continues to perform well. To date, a number of maintenance activities have been undertaken allowing for the deferral of the planned shutdown to 2022. Subsurface and well performance remains good, with aggregate water cut evolution in line with expectations. A successful 3D seismic campaign was completed in July, providing valuable data for the Group to evaluate fully the development potential of the western area of the field, in addition to supporting ongoing optimisation of the main Kraken field, including potential infill opportunities.

Other Upstream assets

Production of 3,504 Boepd was materially lower than in 2020. At the Greater Kittiwake Area ('GKA'), the reduction was driven by a planned four-week shutdown that was concluded in late June, lower production following the failure of a power umbilical to the Mallard and Gadwall wells, as well as natural declines. Performance from Scolty/Crathes in the period was good, reflecting the positive impact of compression and gas lift being introduced in February, although gas compression suffered an outage from late June until mid-August. The power umbilical replacement, which commenced in August, is expected to further improve performance later in September.

Alba has continued to perform broadly in line with Group expectations.

UK Midstream operations

The Sullom Voe Terminal ('SVT') and its related infrastructure has delivered safe and reliable performance, with 100% service availability continuing. The Group continues to work in close collaboration with its stakeholders to ensure the terminal meets existing and future customer needs, while remaining focused on simplification and cost management, which is progressing in line with expectations.

In pipelines, good progress has been made undertaking planned repair and remediation work on delivery infrastructure relating to Kraken, Magnus and Thistle, in addition to in-line pipeline inspection evaluations at GKA. These activities will ensure continued smooth operations across the Group's assets.

To support the ongoing transformation of SVT and EnQuest's energy transition ambitions, the Company established an Infrastructure and New Energy business in August, replacing the former Midstream directorate. The new business will focus on strengthening and extending the life of operations and assessing and delivering new energy opportunities through innovative commercial structures over the medium to long-term to create a hub of growth in infrastructure and renewables at SVT.

UK Decommissioning

Average production from the Dons fields was 337 Boepd, with production ceasing as planned in March 2021. In April 2021, the Northern Producer Floating Production Facility departed the Dons and was handed back to its owners.

Following acceptance by the regulator of the CoP application at Heather during 2020, good progress has been made on decommissioning activities, with sub-sea inspections having been completed ahead of the resumption of the well abandonment programme. At Broom, the application for CoP was approved by the regulator in March 2021.

At Thistle, the first phase of the re-habitation of the platform was successfully completed in June 2021 in line with expectations, with a permanent team now situated on the asset ahead of the well abandonment programme planned for the fourth quarter.

Malaysia operations

In Malaysia, average production was 4,809 Boepd, 42.1% lower than in 2020. This decrease reflects the impact of a riser detachment in late 2020. Production has since improved and been better than expected as a result of the accelerated progress of initial production recovery activities. It is anticipated that replacement of the pipeline and riser will occur in October 2021, returning production to normal levels shortly thereafter.

In late July 2021, a planned five-day maintenance shutdown was successfully completed at PM8/Seligi one day ahead of schedule.

Business development

In January 2021, the Group completed the acquisition of a 40.81% equity interest in and operatorship of the Bressay Oil Field. This acquisition provides a low-cost addition of up to 115 MMbbls (net) 2C resources, around a 65% increase in EnQuest's 2C resources from 164 MMbbls as at 31 December 2020 to 279 MMbbls. The initial consideration was £2.2 million, payable as a carry against 50% of Equinor's net share of costs from the point EnQuest assumed operatorship.

In February 2021, the Group announced the acquisition of a 26.69% non-operated interest in the producing Golden Eagle area from Suncor Energy UK, for an initial consideration of $325 million. The transaction will add incremental production of c.10 kboed, c.19 MMbboe to net 2P reserves and c.4 MMbboe to net 2C resources, in addition to creating c.$170 million NPV (10)¹. Shareholders approved the acquisition at the General Meeting held on 23 July 2021, with the remaining conditions precedent anticipated to be met or waived ahead of the expected completion around the end of September 2021.

In April 2021, the Group signed a SPA with Whalsay Energy Holdings Limited ('WEL') to purchase their entire 100.00% equity interest in the P1078 licence containing the proven Bentley heavy-oil discovery. This discovery is within c.15 kilometres of the Group's existing Kraken and Bressay operated interests, offering further long-term potential development opportunities and other synergies. Upon completion in July, EnQuest funded certain accrued costs and obligations of WEL, which amounted to less than $2 million.

¹ Per GCA CPR estimates and oil price assumptions of: 2021: $51/bbl, 2022: $54/bbl, 2023: $57/bbl, 2024:+: $60/bbl

Liquidity and net debt

Free cash flow generation in the period to 30 June 2021 totalled $141.5 million (2020: $86.8 million), primarily reflecting materially lower cash capital expenditure, partially offset by higher decommissioning spend. During the period, the Sculptor Capital facility was repaid. At 30 June 2021, net debt was $1,183.2 million, down $96.5 million from $1,279.7 million at 31 December 2020. Total cash and available facilities at 30 June 2021 of $303.4 million, including restricted funds and ring-fenced funds held in operational accounts totalling $102.0 million.

In June, the Group announced that it had signed a new senior secured borrowing base debt facility (the 'RBL') of $600 million with an additional amount of $150 million for letters of credit for up to seven years. In July 2021, $360.0 million was drawn down from the RBL. The proceeds were used to repay the entire outstanding balance, including PIK, of $354.5 million on the RCF. In addition, $58.7 million, representing the full amount of the outstanding principal and interest on the BP vendor loan, was repaid. Following shareholder approval of the acquisition of the Golden Eagle assets at the Group's general meeting on 23 July 2021, it is anticipated the remaining funds in the RBL will be used to part finance the required consideration.

In July, the Group successfully completed a capital raise consisting of gross proceeds of approximately £36.1 million ($50.0 million), by way of a firm placing and placing and open offer of 190,122,384 new ordinary shares, at an issue price of 19 pence per new ordinary share.

2021 outlook

Full year production is expected to be at the lower end of the guidance range of between 46,000 and 52,000 Boepd. This reflects expected performances at Magnus, GKA and PM8/Seligi over the course of the second half of the year.

The Group expects operating costs to be approximately $300 million, reflecting lower lease charter credits driven by higher uptime at Kraken, additional production enhancement scopes and topside maintenance activities at Magnus, higher diesel costs and sterling strength . Combined cash capital and abandonment expenditure, excluding costs associated with the PM8/Seligi riser repair where most costs are anticipated to be covered by insurance, is expected to be broadly around $120 million.

As at the end of August, EnQuest has hedged a total of approximately 11 MMbbls for full year 2021 predominantly using costless collars, with an average floor price of approximately $59/bbl and an average ceiling price of approximately $69bbl, with c.6 MMbbls hedged with an average floor of c.$62/bbl and ceiling price of c.$73/bbl in the second half of 2021. For 2022, EnQuest has hedged a total of approximately 6 MMbbls using similar structures, with an average floor price of approximately $61/bbl and an average ceiling price of approximately $75/bbl. For 2023, the Group has hedged a total of approximately 1 MMbbls with an average floor price of approximately $55/bbl and average ceiling price of approximately $73/bbl. This ensures that the Group receives a minimum oil price for its production. The Group continues to layer in hedging over the longer term.

Environmental, Social and Governance

EnQuest has continued to make good progress in reducing its Scope 1 and 2 emissions. Having reduced emissions by 26% between 2018 and 2020, the Group is ahead of the 2025 target set out in the UK Government's North Sea Transition Deal ('NSTD') to reduce emissions by 10% from a 2018 baseline. As previously outlined, the Group has set its own target to reduce emissions by a further 10% from its existing portfolio by the end of 2023 and is on track to achieve this having materially reduced flaring in 2021. Delivering this additional reduction in emissions would also position EnQuest favourably against the 2027 target set out in the NSTD.

The health, safety and wellbeing of EnQuest's employees is the Company's top priority. Following recent COVID-19 related announcements in the UK, a phased approach back to the office has commenced with the necessary precautions in place, while testing of the offshore workforce continues to be undertaken regularly by the Group. In Malaysia, the Group has evolved its strategy to accommodate the requirement by the local government for all personnel to quarantine for 14 days ahead of deployment to an asset. The Group has amended its shift patterns to facilitate this whilst maintaining safe operations. The Group remains compliant with UK, Malaysia and Dubai government and industry policy and will continue working closely with a variety of stakeholders, including industry and medical organisations, to ensure its operational response and advice to its workforce is appropriate and commensurate with the prevailing expert advice. The Group's day-to-day operations continue without being materially affected by COVID-19. During the period, the Group also achieved a lost time incident frequency ('LTI') rate of zero, with Heather achieving two years LTI free in July, which remains materially below the UKCS benchmark. There continues to be a focus on asset integrity and the Group remains committed to ensuring that the ongoing asset integrity review appropriately identifies key focus areas.

In July, EnQuest published its Diversity & Inclusion global strategy and accompanying policy update to help the Group achieve specific improvements. Set out in the strategy were seven distinct commitments ranging from committing to challenging personal bias, to ensuring that diversity within EnQuest remains a key focus area. In addition, EnQuest has set some specific targets for women in senior grade and management positions, as well as ethnic minorities in Executive leadership roles. The aim is to meet these targets by 2025.

In February, the Board was pleased to appoint Liv Monica Stubholt as a Non-Executive Director of the EnQuest Board. Liv Monica also became a member of the Audit Committee and the Safety, Climate and Risk Committee. Her appointment builds on the Board's extensive experience in the energy industry and further strengthens its governance position.

- Ends -

For further information, please contact:

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

Tulchan Communications	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 09.00 today - London time. The presentation will be accessible via a webcast by clicking here . A conference call facility will also be available at 09.00 on the following numbers:

Conference call details:

UK : +44 (0) 800 279 6619

International: +44 (0) 207 192 8338

Confirmation Code: 11104072

Notes to editors

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

ENQUEST

EnQuest is providing creative solutions through the energy transition. As an independent production and development company with operations in the UK North Sea and Malaysia, the Group's strategic vision is to be the operator of choice for maturing and underdeveloped hydrocarbon assets by focusing on operational excellence, differential capability, value enhancement and financial discipline.

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

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

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

FINANCIAL REVIEW

Financial overview

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

Production on a working interest basis decreased by 30.1% to 46,187 Boepd, compared to 66,055 Boepd in 2020.

Revenue for the six months ended 30 June 2021 was $518.3 million, 15.2% higher than the same period in 2020 ($450.0 million), reflecting the materially higher oil prices offset by the reduction in production. The Group's commodity hedge programme resulted in realised losses of $32.9 million in the first half of 2021 (2020: gains of $35.2 million).

The Group's operating costs of $153.0 million were 12.2% lower than in the same period in 2020 ($174.3 million). This reduction primarily reflects reduced tariff and transportation costs due to lower production for the first half of 2021. Production costs are broadly flat year on year as lower costs due to the cessation of production at the Dons in March 2021 and Alma/Galia in June 2020 have been offset by remediation costs at Magnus and lower lease charter credits reflecting higher uptime at Kraken driven by the continued strong performance of the FPSO. Unit costs increased to $19.3/Boe (2020: $14.4/Boe), primarily reflecting lower production.

Other cost of sales for the six months ended 30 June 2021 of $53.3 million were 45.2% higher than the same period in 2020 ($36.7 million), reflecting the higher cost of Magnus-related third-party gas purchases following the increase in the market price for gas.

EBITDA for the six months ended 30 June 2021 was $345.4 million, up 7.7% compared to the same period in 2020 ($320.8 million), driven by higher revenue.

	H1 2021 $ million	H1 2020 $ million
Profit/(loss) from operations before tax and finance income/(costs)	175.4	24.6
Depletion and depreciation	157.0	252.3
Change in provision	5.7	45.9
Change in well inventories	1.0	19.0
Net foreign exchange (gain)/loss	6.3	(21.0)
EBITDA	345.4	320.8

EnQuest's net debt decreased by $96.5 million to $1,183.2 million at 30 June 2021 (31 December 2020: $1,279.7 million). This includes $244.4 million of interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing ('PIK') (31 December 2020: $205.8 million) (see note 8 for further details).

	Net debt/(cash)¹
	30 June 2021 $ million	31 December 2020 $ million
Bonds	1,091.0	1,048.3
Multi-currency revolving credit facility ('RCF')	353.1	377.3
Sculptor Capital facility	-	67.7
SVT Working Capital Facility	14.1	9.2
Cash and cash equivalents²	(275.0)	(222.8)
Net debt	1,183.2	1,279.7

Note:

1 See reconciliation of net debt within the 'Glossary - Non-GAAP measures' starting on page 31

2 Cash and cash equivalents includes $30.7 million of restricted cash (2020: $1.6 million), of which $29.1 million is held under decommissioning security agreements, which was transferred to unrestricted cash in July 2021 after the initial drawdown of the RBL

In January 2021, EnQuest made a voluntary early repayment of $25.0 million on the RCF. In July 2021, $360.0 million was drawn down from the Group's new RBL. The proceeds were used to repay the entire outstanding balance on the RCF, which at the time of repayment was $354.5 million, including PIK and accrued interest. Also in July, $58.7 million, representing the full amount of the outstanding principal and interest on the Magnus vendor loan, was repaid.

The strong production performance at Kraken combined with higher oil prices enabled the full repayment of the $67.7 million outstanding balance on the Sculptor Capital facility in the period to 30 June 2021.

$37.8 million of bond interest was settled through the issue of additional notes ('PIK') and capitalised to the principal of the facilities in the period, reflecting an average oil price of less than $65/bbl over the relevant cash payment condition period in accordance with the terms of the bonds.

The Group continues to have unrestricted access to its UK corporate tax losses, which at 30 June 2021 were $3,173.0 million (2020: $3,183.9 million). In the current environment, no significant corporation tax or supplementary charge is expected to be paid on UK operational activities for the foreseeable future. The Group paid cash corporate income tax on the Malaysian assets, which will continue throughout the life of the production sharing contract.

Income statement

Revenue

On average, market prices for crude oil in the first half of 2021 were significantly higher than in the same period of 2020. The Group's average realised oil price excluding the impact of hedging was $67.3/bbl for the six months ended 30 June 2021, compared to $39.9/bbl received during the first half of 2020. Revenue is predominantly derived from crude oil sales, which for the first half of 2021 totalled $490.5 million, 30.6% higher than in the same period of 2020 ($375.5 million), reflecting the materially higher oil prices offset by the reduction in production. Revenue from the sale of condensate and gas in the period was $57.9 million (2020: $27.6 million), primarily reflecting higher market prices for condensate and gas. Gas revenue mainly relates to the onward sale of third-party gas purchases not required for injection activities at Magnus. Tariffs and other income generated $2.8 million (2020: $11.7 million). The Group's commodity hedges and other oil derivatives contributed $32.9 million of realised losses (2020: gains of $35.2 million), as a result of the timing at which the hedges were entered into. The Group's average realised oil price including the impact of hedging was $62.8/bbl in the first half of 2021, 44.0% higher than during the first half of 2020 ($43.6/bbl).

Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP measures' starting on page 31

Cost of sales¹

	H1 2021 $ million	H1 2020 $ million
Production costs	139.5	137.7
Tariff and transportation expenses	21.7	36.1
Realised loss/(gain) on derivatives related to operating costs	(8.2)	0.5
Operating costs	153.0	174.3
(Credit)/charge relating to the Group's lifting position and hydrocarbon inventory	(26.1)	(48.5)
Depletion of oil and gas assets	153.1	248.4
Other cost of sales	53.3	36.7
Cost of sales	333.3	410.9
Unit operating cost²	$/Boe	$/Boe
- Production costs	16.7	11.4
- Tariff and transportation expenses	2.6	3.0
Average unit operating cost	19.3	14.4

Notes:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 31

2 Calculated on a working interest basis

Cost of sales were $ 333.3 million for the six months ended 30 June 2021, 18.9% lower than in same period of 2020 ($410.9 million).

Operating costs decreased by $21.3 million, primarily reflecting low tariff and transport costs due to lower production for the first half of 2021. Production costs are broadly flat year on year as lower costs due to assets ceasing production have been offset by remediation costs at Magnus and lower lease charter credits driven by higher uptime at Kraken . Unit operating costs increased by 34.0% to $19.3/Boe (2020: $ 14.4 /Boe) as a result of lower production.

The credit relating to the Group's lifting position and hydrocarbon inventory for the six months ended 30 June 2021 was $26.1 million (2020: credit of $48.5 million). This reflects an increase in the net underlift position from $3.0 million, at 31 December 2020 to $32.0 million at 30 June 2021.

Depletion expense of $153.1 million was 38.4% lower than in the same period in 2020 ($248.4 million), mainly reflecting the decisions to cease production at the Dons and Alma/Galia and a decrease in the unit-of-production rate arising from impairments recognised in the period ended 31 December 2020.

Other cost of sales for the six months ended 30 June 2021 of $53.3 million were higher than the same period in 2020 ($36.7 million), reflecting the higher cost of Magnus-related third-party gas purchases following the increase in the market price for gas.

Other income and expenses

Net other expense of $9.5 million (2020: net other expense of $11.0 million) is primarily due to recognising $6.3 million expenses in relation to the increase in the decommissioning provision of fully impaired assets and foreign exchange losses of $6.4 million, partially offset by other income. 2020 primarily reflected a $45.9 million recognition of an increase in the decommissioning provision of the fully impaired assets offset by foreign exchange gains of $21.0 million and the $10.4 million gain on the termination of the Tanjong Baram risk service contract.

Finance costs

Finance costs of $86.6 million were 4.7% lower than in the comparative period (2020: $90.9 million). This decrease was primarily driven by a $7.9 million decrease in interest charges associated with the Group's loans (2021: $10.8 million; 2020: $18.7 million) offset by a $3.4 million increase in bond interest (2021: $37.5 million; 2020: $34.1 million). Other finance costs included lease liability interest of $23.5 million (2020: $26.1 million), $8.5 million on unwinding of discount on decommissioning provisions and other liabilities (2020: $7.5 million), $3.7 million amortisation of arrangement fees for the Sculptor Capital financing facility and bonds (2020: $2.8 million) and other financial expenses of $2.6 million (2020: $1.7 million), primarily being the cost for surety bonds to provide security for decommissioning liabilities.

Taxation

The tax credit for the six months ended 30 June 2021 of $19.4 million (2020: $71.5 million tax credit), excluding exceptional items, is mainly due to the Ring Fence Expenditure Supplement ('RFES') on UK activities generated in the year.

Remeasurements and exceptional items

Remeasurements and exceptional items resulting in a post-tax net loss of $ 164.6 million have been disclosed separately for the six month period ended 30 June 2021 (2020 restated: loss of $478.7 million).

Revenue included unrealised losses of $37.0 million in respect of the mark-to-market movement on the Group's commodity contracts (2020: unrealised losses of $11.3 million).

Other income included a $27.5 million gain in relation to the fair value recalculation of the Magnus contingent consideration reflecting a change in the payment profile (2020: $161.9 million gain). Finance costs mainly relates to the unwinding of contingent consideration from the acquisition of Magnus and associated infrastructure and interest charged on the vendor loan of $30.3 million (2020: $39.7 million).

A net tax charge of $124.9 million (2020 restated: $170.6 million see Note 2 Basis of preparation - Restatements) has been presented as exceptional, representing the tax impact of the above items and a non-cash derecognition of undiscounted deferred tax assets reflecting changes in the Group's forecast assumptions. EnQuest continues to have unrestricted access to its full unrecognised UK North sea corporate tax losses of $3,173.0 million at 30 June 2021.

IFRS results

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

EnQuest IFRS revenue reflects the Group's Business performance revenue, adjusted for the impact of unrealised movements on derivative commodity contracts. Business performance cost of sales is similarly adjusted for the impact of unrealised movements on derivative contracts (applicable to first half 2020 only). Taking account of these items, and the other exceptional items included within the Group income statement which are principally related to the change in fair value of contingent consideration payable and 2020 impairment charges, EnQuest's IFRS profit from operations before tax and finance costs was $165.9 million (2020: loss of $243.8 million), IFRS profit before tax was $49.1 million (2020: loss of $373.4 million), and IFRS loss after tax was $56.4 million (2020 restated: loss of $472.4 million).

Earnings per share

The Group's Business performance basic profit per share was 6.6 cents (2020 profit per share: 0.4 cents) and diluted profit per share was 6.5 cents (2020 profit per share: 0.4 cents).

The Group's reported basic loss per share was 3.4 cents (2020 loss per share restated: 28.6 cents) and reported diluted loss per share was 3.4 cents (2020 loss per share restated: 28.6 cents).

Cash flow and liquidity

Net debt at 30 June 2021 amounted to $1,183.2 million, including PIK of $244.4 million, compared with net debt of $1,279.7 million at 31 December 2020, including PIK of $205.8 million. The movement in net debt was as follows:

	$ million
Net debt 1 January 2021	(1,279.7)
Net cash flows from operating activities	246.9
Cash capital expenditure	(15.9)
Net interest and finance costs paid	(16.9)
Finance lease payments	(57.3)
Repayments on Magnus financing and profit share	(12.3)
Non-cash capitalisation of interest	(30.2)
Other movements, primarily net foreign exchange on cash and debt	(17.8)
Net debt 30 June 2021¹	(1,183.2)

Note:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 31

The Group's reported net cash flows from operating activities for the six month period ended 30 June 2021 were $246.9 million, down 10.0% compared to comparative period of 2020 ($274.4 million). Key drivers are materially higher decommissioning spend and negative working capital movements, partially offset by the higher revenue and lower cost of sales.

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

	H1 2021 $ million	H1 2020 $ million
North Sea	11.0	99.4
Malaysia	3.9	1.9
Exploration and evaluation	1.0	0.1
	15.9	101.4

Cash capital expenditure in the period ended 30 June 2021 primarily related to Magnus well interventions and the PM8/Seligi pipeline replacement projects. Cash capital expenditure in 2020 primarily related to drilling campaigns undertaken at Kraken and Magnus.

Balance sheet

The Group's total asset value has decreased by $72.7 million to $3,789.9 million at 30 June 2021 (2020 restated: $3,862.6 million).

Net current liabilities have decreased to $443.4 million as at 30 June 2021 (2020: $536.9 million). Included in the Group's net current liabilities are $65.9 million of estimated future obligations where settlement is subject to the financial performance at Magnus (2020: $73.7 million).

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

PP&E has decreased by $122.1 million to $2,511.8 million at 30 June 2021 from $2,633.9 million at 31 December 2020 (see note 7). This decrease encompasses the capital additions to PP&E of $28.0 million, a net increase of $7.1 million for changes in estimates for decommissioning and other provisions, more than offset by depletion and depreciation charges of $157.0 million.

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

	1H 2021 $ million	H1 2020 $ million
North Sea	20.8	71.8
Malaysia	7.2	0.7
	28.0	72.5

Trade and other receivables

Trade and other receivables increased by $62.2 million to $180.9 million at 30 June 2021 compared with $118.7 million at 31 December 2020. The increase is driven by the increase in the Group's underlift position ($29.0 million) and timing of settlements.

Cash and net debt

The Group had $275.0 million of cash and cash equivalents at 30 June 2021 and $1,183.2 million of net debt, including PIK and capitalised interest of $244.4 million (2020: $222.8 million, $1,279.7 million and $214.2 million, respectively). Cash and cash equivalents includes $30.7 million of restricted cash (2020: $1.6 million). Restricted cash of $29.1 million was released in July 2021 following the initial drawdown from the RBL.

Net debt comprises the following liabilities:

· $263.9 million principal outstanding on the £155.0 million retail bond, including interest capitalised as PIK of $49.2 million (2020: $249.2 million and $39.4 million, respectively);

· $827.2 million principal outstanding on the high yield bond, including interest capitalised as PIK of $177.2 million (2020: $799.2 million and $149.2 million, respectively);

· $353.1 million of credit facility, comprising amounts drawn down of $335.0 million and interest capitalised as PIK of $18.1 million (2020: $377.3 million, $360.0 million and $17.3 million, respectively);

· nil on the Sculptor Capital facility (2020: $67.7 million); and

· $14.1 million relating to the SVT Working Capital Facility (2020: $9.2 million).

The Group continues to review its capital structure and longer term solutions.

Provisions

The Group's decommissioning provision decreased by $9.8 million to $768.4 million at 30 June 2021 (2020: $778.2 million).

The Thistle decommissioning provision decreased by $13.8 million in the six months ended 30 June 2021 to $39.3 million (2020: $53.1 million) primarily related to utilisations. Other provisions also decreased in the period to $4.5 million (2020: $9.1 million).

Contingent consideration

The contingent consideration related to the Magnus acquisition decreased by $13.5 million. In the first six months of 2021, EnQuest paid $16.3 million to BP (2020: $30.1 million). The payment primarily related to the $15.0 million partial repayment of the 75% interest vendor loan and interest and $1.0 million relating to BP's entitlement to share in the cash flows from the 75% interest. A change in fair value estimate charge of $27.5 million (2020: $161.9 million) and finance costs of $30.3 million (2020: $39.7 million) was recognised in the period.

Income tax

The Group had an income tax receivable of $1.3 million (2020: $5.6 million receivable) related to UK corporation tax repayments and North Sea research and development expenditure credits.

Deferred tax

The Group's net deferred tax asset has decreased from $653.4 million at 31 December 2020 (restated) to $554.3 million at 30 June 2021. This is driven by the derecognition of undiscounted deferred tax assets reflecting changes in the Group's forecast assumptions, and movements in relation to unrealised hedging, capital expenditure and UK RFES. The restatement for the period ended 30 June 2020 movement relates to a previous inconsistency in the calculation of deferred tax and the future cash flows used to support the recognition of that deferred tax and the deferred tax asset associated with other available losses, see Note 2 Basis of preparation - Restatements. EnQuest continues to have access to its full UK corporate tax losses carried forward at 30 June 2021 amounting to $3,173.0 million (31 December 2020: $3,183.9 million).

Trade and other payables

Trade and other payables of $310.1 million at 30 June 2021 are $54.9 million higher than at 31 December 2020 ($255.2 million). The full balance is payable within one year.

Leases obligations

As at 30 June 2021, the Group held lease liabilities of $620.1 million (31 December 2020 $647.8 million).

Financial risk management

The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. The disclosures in relation to financial risk management objectives and policies, including the policy for hedging, and the disclosures in relation to exposure to oil price, foreign currency and credit and liquidity risk, are included in note 30 of the Group's 2020 Annual report.

Going concern disclosure

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

The Group continues to monitor actively the impact on operations from COVID-19 and the health, safety and wellbeing of its employees is its top priority. The Group remains compliant with UK, Malaysia and Dubai government and industry policy. The Group has also been working with a variety of stakeholders, including industry and medical organisations, to ensure its operational response and advice to its workforce is appropriate and commensurate with the prevailing expert advice. At the time of publication of this interim report, the Group's day-to-day operations continue without being materially affected by COVID-19.

On 11 June 2021, the Group announced it had signed a new senior secured borrowing base debt facility (the 'RBL') of $600 million and an additional amount of $150 million for letters of credit, for up to seven years. The RBL contains covenants related to the ratio of net financial indebtedness to EBITDA and minimum cash headroom requirements. The RBL also includes a cash sweep mechanism, whereby any unrestricted cash in excess of $75 million is swept to repay outstanding amounts at calendar quarter ends. The new facility enables the Group to simplify its existing capital structure and finance the acquisition of a 26.69% interest in the Golden Eagle assets.

Drawdown of the new facility is in two steps:

· Step 1 - Refinancing existing debt; On 21 July 2021, the Group drew down $360.0 million from the new facility and repaid in full its existing senior credit facility and the outstanding BP vendor loan associated with the acquisition of the 75% interest in Magnus;

· Step 2 - Financing the acquisition of the interest in the Golden Eagle assets. The Base Case assumes the step 2 drawdown on the new facility and related completion of the acquisition of Golden Eagle at the end of third quarter 2021. In addition to the RBL, the initial consideration of $325.0 million will be funded through the combination of the equity raise and the interim period post-tax cash flows generated from the economic date of 1 January 2021.

In accordance with the amortisation schedule of the RBL, there is a $300 million reduction in the utilisation limit from the $600 million facility occurring within the going concern period. The amortisation schedule is structured so that the RBL is fully repaid by June 2023 in the event the Group's existing high yield bond is not refinanced by this time.

Upon refinancing of the Group's high yield bond (which, given the bond matures in October 2023, is anticipated to occur outside the going concern period), the maturity of the new facility is extended to seven years from its signing date, or the point at which the remaining economic reserves for all borrowing base assets are projected to fall below 25% of the initial economic reserves forecast, if earlier.

The Group's latest assessment of the 2021 and 2022 forecast underpins management's base case ('Base Case') and uses oil price assumptions of $70.0/bbl from August to December 2021 and $68.0/bbl for 2022, adjusted for hedging activity undertaken by the Group. These oil prices are broadly in line with current consensus.

The Base Case has been subjected to stress testing by considering the impact of the following plausible downside risks (the 'Downside Case'):

· 10.0% discount to Base Case prices resulting in Downside Case prices of $63.0/bbl from August to December 2021 and $61.2/bbl for 2022;

· Production risking of c.5.0% for 2022; and

· A 2.5% increase to operating costs for 2022.

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 this interim report. The Directors have also performed reverse stress testing on the Base Case and a price of less than $55.0/bbl is required to maintain $75 million of headroom as required by the RBL in the going concern period.

Should circumstances arise that differ from the Group's projections, the Directors believe that a number of mitigating actions, including asset sales or other funding options, can be executed successfully in the necessary timeframe to meet debt repayment obligations as they become due and in order to maintain liquidity.

After making appropriate enquiries and assessing the progress against the forecast, 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 Group's risks and uncertainties were set out in the Annual Report and Accounts 2020. This was published in April 2021 and the below risks and uncertainties reflect the impacts of climate change and COVID-19 on the business, where relevant. Following the successful signing of a new senior secured borrowing base debt facility in June 2021, which has enabled the Group to repay the entire outstanding amount due, including payment in kind, on the Group's RCF ahead of maturity in October 2021, the financial risks and uncertainties for the Group have decreased when compared to those disclosed in the Group's Annual Report and Accounts 2020. All of the Group's other risks and uncertainties remain unchanged from those published in April 2021.

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'):

o 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:

o A material decline in oil and gas prices adversely affects the Group's operations and financial condition.

· Production:

o 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).

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

o The Group's delivery infrastructure in the UK North Sea is, to a significant extent, dependent on the Sullom Voe Terminal.

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

· Project execution and delivery:

o The Group's success will be partially dependent upon the successful execution and delivery of potential future projects that are undertaken (including decommissioning of certain fields in the UK).

· Subsurface risk and reserves replacement:

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

· Financial:

o 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 the terms of its new senior secured borrowing base debt facility.

o Similar conditions could impact the Group's ability to refinance the bonds ahead of maturity in October 2023.

· Human resources:

o 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 given the potential impacts of COVID-19, could also impact the operations of the Group.

· Reputation:

o 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.

o It is increasingly important EnQuest clearly articulates its approach to and benchmarks its performance against relevant and material ESG factors.

· Fiscal risk and government take:

o 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.

· Joint venture partners:

o Failure by joint venture parties to fund their obligations .

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

· Competition:

o 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 .

· Portfolio concentration:

o The Group's assets are primarily concentrated in the UK North Sea around a limited number of infrastructure hubs and some 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.

· International business:

o 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 (e.g. 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.

· IT security and resilience:

o 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.

For full details of these risks and uncertainties, please see the Group's Annual Report and Accounts 2020 .

Group Income Statement

For the six months ended 30 June 2021

		2021			2020 restated⁽ⁱ⁾
	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⁽ⁱ⁾	5	518,287	(36,973)	481,314	450,004	(11,278)	438,726
Cost of sales		(333,262)	-	(333,262)	(410,870)	(9,201)	(420,071)
Gross profit/(loss)		185,025	(36,973)	148,052	39,134	(20,479)	18,655
Net impairment to oil and gas assets		-	-	-	-	(409,800)	(409,800)
General and administration expenses		(130)	-	(130)	(3,538)	-	(3,538)
Other income⁽ⁱ⁾		4,333	27,490	31,823	34,974	161,908	196,882
Other expenses		(13,873)	-	(13,873)	(45,964)	-	(45,964)
Profit/(loss) from operations before tax and finance income/(costs)		175,355	(9,483)	165,872	24,606	(268,371)	(243,765)
Finance costs		(86,603)	(30,299)	(116,902)	(90,909)	(39,733)	(130,642)
Finance income		102	-	102	1,050	-	1,050
Profit/(loss) before tax		88,854	(39,782)	49,072	(65,253)	(308,104)	(373,357)
Income tax		19,411	(124,855)	(105,444)	71,469	(170,550)	(99,081)
Profit/(loss) for the year attributable to owners of the parent		108,265	(164,637)	(56,372)	6,216	(478,654)	(472,438)
Total comprehensive profit/(loss) for the period, attributable to owners of the parent				(56,372)			(472,438)

(i) See Note 2 Basis of preparation - Restatements

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

Earnings per share	6	$	$	$	$
Basic		0.066	(0.034)	0.004	(0.286)
Diluted		0.065	(0.034)	0.004	(0.286)

The attached notes 1 to 14 form part of these condensed Group financial statements.

Group Balance Sheet

At 30 June 2021

	Notes	30 June 2021 $'000	31 December 2020 restated⁽ⁱ⁾ $'000
		Unaudited	Audited
ASSETS
Non-current assets
Property, plant and equipment	7	2,511,835	2,633,917
Goodwill		134,400	134,400
Intangible oil and gas assets		33,003	27,546
Deferred tax assets		560,035	659,803
Other long term assets	9	34,817	7
		3,274,090	3,455,673
Current assets
Inventories		58,563	59,784
Trade and other receivables		180,910	118,715
Current tax receivable		1,307	5,601
Cash and cash equivalents		275,034	222,830
		515,814	406,930
TOTAL ASSETS		3,789,904	3,862,603
EQUITY AND LIABILITIES
Equity
Share capital and premium		345,420	345,420
Share-based payment reserve		4,531	1,016
Retained earnings		(311,591)	(255,219)
TOTAL EQUITY		38,360	91,217
Non-current liabilities
Borrowings	8	-	37,854
Bonds	8	1,088,328	1,045,041
Lease liabilities		513,522	548,407
Contingent consideration	10	442,837	448,384
Provisions	11	741,938	741,453
Deferred tax liabilities		5,691	6,385
		2,792,316	2,827,524
Current liabilities
Borrowings	8	367,164	414,430
Lease liabilities		106,618	99,439
Contingent consideration	10	65,928	73,877
Provisions	11	70,360	98,954
Trade and other payables		310,083	255,155
Other financial liabilities	9	38,980	2,007
Current tax payable		95	-
		959,228	943,862
TOTAL LIABILITIES		3,751,544	3,771,386
TOTAL EQUITY AND LIABILITIES		3,789,904	3,862,603

(i) See Note 2 Basis of preparation - Restatements

The attached notes 1 to 14 form part of these condensed Group financial statements.

Group Statement of Changes in Equity

For the six months ended 30 June 2021

	Share capital and share premium $'000	Merger reserve⁽ⁱ⁾ $'000	Share-based payments reserve $'000	Retained earnings $'000	Total $'000
	Unaudited	Unaudited	Unaudited	Unaudited	Unaudited
Balance at 1 January 2020	345,420	662,855	(1,085)	(448,129)	559,061
Profit/(loss) for the year (restated)⁽ⁱⁱ⁾	-	-	-	(472,438)	(472,438)
Total comprehensive loss for the year (restated) ⁽ⁱⁱ⁾	-	-	-	(472,438)	(472,438)
Share-based payment	-	-	2,616	-	2,616
Balance at 30 June 2020 (restated)⁽ⁱⁱ⁾	345,420	662,855	1,531	(920,567)	89,239

Balance at 1 January 2021	345,420	-	1,016	(255,219)	91,217
Profit/(loss) for the year	-	-	-	(56,372)	(56,372)
Total comprehensive loss for the year	-	-	-	(56,372)	(56,372)
Share-based payment	-	-	3,515	-	3,515
Balance at 30 June 2021	345,420	-	4,531	(311,591)	38,360

(i) In the second half of 2020, the merger reserve was released to retained earnings as the assets which gave rise to its original recognition were fully written down.

(ii) See Note 2 Basis of preparation - Restatements

The attached notes 1 to 14 form part of these condensed Group financial statements.

Group Statement of Cash Flows

For the six months ended 30 June 2021

	Notes	30 June 2021 $'000	30 June 2020 $'000 restated⁽ⁱ⁾
		Unaudited	Unaudited
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations	13	287,879	282,560
Cash received/(paid) on sale/(purchase) of financial instruments		-	4,417
Decommissioning spend		(38,661)	(7,082)
Income taxes paid		(2,276)	(5,458)
Net cash flows from/(used in) operating activities		246,942	274,437
INVESTING ACTIVITIES
Purchase of property, plant and equipment		(14,986)	(101,385)
Purchase of intangible oil and gas assets		(936)	-
Net cash received on termination of Tanjong Baram risk service contract		-	17,086
Repayment of Magnus contingent consideration - Profit share	10	(968)	(21,088)
Deposit for Golden Eagle acquisition		(3,000)	-
Interest received		83	696
Net cash flows (used in)/from investing activities		(19,807)	(104,691)
FINANCING ACTIVITIES
Repayment of loans and borrowings		(88,170)	(118,906)
Repayment of Magnus contingent consideration - Vendor loan	10	(11,362)	(4,675)
Repayment of obligations under financing leases		(57,286)	(56,139)
Interest paid		(15,795)	(21,000)
Other finance costs paid		(1,236)	(1,118)
Net cash flows from/(used in) financing activities		(173,849)	(201,838)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS		53,286	(32,092)
Net foreign exchange on cash and cash equivalents		(1,082)	(4,989)
Cash and cash equivalents at 1 January		222,830	220,455
CASH AND CASH EQUIVALENTS AT 30 June		275,034	183,374
Reconciliation of cash and cash equivalents
Cash and cash equivalents		244,331	181,800
Restricted cash ⁽ⁱⁱ⁾		30,703	1,574
Cash and cash equivalents per balance sheet		275,034	183,374

(i) See Note 2 Basis of preparation - Restatements

(ii) At 30 June 2021, restricted cash includes $29.1 million held under decommissioning security agreements, which was transferred to unrestricted cash in July 2021 after the initial drawdown of the RBL.

The attached notes 1 to 14 form part of these condensed Group financial statements.

Notes to the Half Year Condensed Financial Statements

For the period ended 30 June 2021

1. Corporate information

EnQuest PLC ('EnQuest' or the 'Company') is a public company limited by shares incorporated in the United Kingdom under the Companies Act and is registered in England and Wales and listed on the London Stock Exchange and on the Stockholm NASDAQ OMX.

The principal activities of the Company and its subsidiaries (together the 'Group') are to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner.

The Group's half year condensed financial statements for the six months ended 30 June 2021 were authorised for issue in accordance with a resolution of the Board of Directors on 1 September 2021.

2. Basis of preparation

The interim condensed consolidated financial statements of the Group for the six months ended 30 June 2021 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 as at 31 December 2020.

The financial information contained in this announcement does not constitute statutory financial statements within the meaning of section 435 of the Companies Act 2006.

Consolidated statutory accounts for the year ended 31 December 2020, on which the auditor gave an unqualified audit report, have been filed with the Registrar of Companies. The report contained a material uncertainty related to going concern, which is no longer the case given the Group signed a new RBL facility in June 2021.

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 7. 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 2021 are materially consistent with those followed in the preparation of the Group's financial statements for the year ended 31 December 2020, except for the change in accounting policy related to the presentation of rental income as noted under restatements below and the adoption of new standards effective as of 1 January 2021 as set out below. 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 were disclosed in the Group's 2020 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.

Impairment testing assumptions

The Group's oil price assumptions were revised during the first half of 2021 as shown below. The assumptions up to 2023 were increased to reflect an improved demand outlook. For periods after 2023, the Group's longer term price assumption is unchanged from that disclosed in the Group's 2020 annual report and accounts at $60/bbl (in real 2020 terms) inflated at 2% per annum from 2024.

Second

half 2021

2022

2023

Brent oil ($/bbl)

The discount rate used in impairment testing is unchanged from that disclosed in the Group's 2020 annual report and accounts.

Restatements

Change in accounting policy - presentation of rental income

EnQuest receives rental income for subleasing space in its corporate offices. The Group previously presented the rental income associated with office subleases within revenue and other operating income in the income statement. The Group has determined that the revenue derived from this income is not related to the principal activities of the Group and should be presented within other income in the income statement. Comparative information has been restated resulting in a $0.7 million reduction in revenue and other operating income and a $0.7m increase in other income. There is no impact on comparative information for profit/(loss) from operations before tax and finance income/(costs) or earnings per share.

Presentation of Group Statement of Cash Flows

Following a review of the Group's primary statements, the Group has updated the presentation of the Group Statement of Cash Flows to reconcile to cash and cash equivalents per the balance sheet. In previous years, the Group Statement of Cash Flows was reconciled to cash and cash equivalents excluding restricted cash. Following this change, the presentation of the Group Statement of Cash Flows in 2020 has been restated which has resulted in a $0.7 million reduction in cash flows from operating activities.

Deferred Tax Asset Restatement:

Subsequent to the publication of the Group's 2020 consolidated financial statements and as part of the preparation of this interim report, the Group has determined there was an inconsistency in the calculation of the deferred tax asset recognised on the balance sheet associated with Magnus contingent consideration and the relevant estimated future cash flows used in the calculation of future taxable profits to support the recognition of this deferred tax asset and the deferred tax asset associated with other available tax losses. This inconsistency resulted in excess deferred tax being derecognised within Remeasurements and exceptional items of $146.6 million with respect to the period ended 30 June 2020 and $155.9 million as at and for the year ended 31 December 2020. There are no changes to the underlying amounts recognised in relation to contingent consideration or to amounts recognised in respect of deferred tax in earlier periods. The tables below reflect the corrections to the comparative periods which are disclosed in this interim report.

Group income statement

	2020 (As previously reported)				Restatement adjustment		2020 restated
	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
Profit/(loss) before tax	(65,253)	(308,104)	(373,357)			(65,253)		(308,104)	(373,357)
Income tax	71,469	(317,120)	(245,651)	146,570		71,469		(170,550)	(99,081)
Profit/(loss) for the year attributable to owners of the parent	6,216	(625,224)	(619,008)	146,570		6,216		(478,654)	(472,438)
Total comprehensive profit/(loss) for the period, attributable to owners of the parent			(619,008)	146,570					(472,438)

Earnings per share	$	$		$	$
Basic	0.004	(0.374)	0.088	0.004	(0.286)
Diluted	0.004	(0.374)	0.088	0.004	(0.286)

Group balance sheet

	2020 (As previously reported) $'000	Restatement adjustment	2020 restated $'000
	Audited		Audited
ASSETS
Non-current assets
Deferred tax assets	503,946	155,857	659,803
TOTAL ASSETS	3,706,746	155,857	3,862,603
EQUITY AND LIABILITIES
Equity
Retained earnings	(411,076)	155,857	(255,219)
TOTAL EQUITY	(64,640)	155,857	91,217
TOTAL EQUITY AND LIABILITIES	3,706,746	155,857	3,862,603

New and amended standards adopted by the Group

Interest Rate Benchmark Reform - Phase II: Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16

The amendments provide temporary reliefs and include practical expedients which address the financial reporting effects when an interbank offered rate is replaced with an alternative nearly risk-free interest rate. The Group is currently assessing the impact on contracts and arrangements that are linked to existing interest rate benchmarks, for example, borrowings.

These amendments had no impact on the interim condensed consolidated financial statements of the Group. The Group intends to use the practical expedients in future periods if they become applicable.

3. Segment information

Segment information for the six month period is as follows:

Period ended 30 June 2021 $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(ii)	Consolidated
Revenue:
Revenue from contracts with customers	502,071	46,782	-	548,853	-	548,853
Other operating income	2,232	-	110	2,342	(69,881)	(67,539)
Total revenue	504,303	46,782	110	551,195	(69,881)	481,314
Segment profit/(loss)(iii)	215,805	15,617	(3,826)	227,596	(61,724)	165,872

Restated Periodended 30 June 2020⁽ⁱ⁾ $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(ii)	Consolidated
Revenue:
Revenue from contracts with customers	377,808	33,277	-	411,085	-	411,085
Other operating income⁽ⁱ⁾	3,480	-	210	3,690	23,951	27,641
Total revenue	381,288	33,277	210	414,775	23,951	438,726
Segment profit/(loss)(iii)	(291,439)	10,847	16,443	(264,149)	20,384	(243,765)

(i) Comparative information for 2020 has been restated for the changes to the presentation of rental income effective 1 January 2021. For more information, see Note 2 Basis of preparation - Restatements

(ii) 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

(iii) 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 2021 $'000	Period ended 30 June 2020 $'000
Segment profit/(loss)	227,596	(264,149)
Finance income	102	1,050
Finance expense	(116,902)	(130,642)
Gain/(loss) on derivatives⁽ⁱ⁾	(61,724)	20,384
Profit/(loss) before tax	49,072	(373,357)

(i) Includes $24.7 million realised losses (2020: $34.7 million realised gains) on derivatives and $37.0 million unrealised losses (2020: $14.3 million unrealised losses) on derivatives

4. Remeasurements and exceptional items

Period ended 30 June 2021 $'000	Fair value remeasurement(i)	Impairments and write offs(ii)	Other(iii)	Total
Revenue and other operating income	(36,973)	-	-	(36,973)
Other income	27,490	-	-	27,490
Finance costs	-	-	(30,299)	(30,299)
	(9,483)	-	(30,299)	(39,782)
Tax on items above	3,315	-	11,350	14,665
Derecognition of undiscounted deferred tax asset(iv)	-	(139,520)	-	(139,520)
	(6,168)	(139,520)	(18,949)	(164,637)

Periodended 30 June 2020 restated $'000	Fair value remeasurement(i)	Impairments and write offs(ii)	Other(iii)	Total
Revenue and other operating income	(11,278)	-	-	(11,278)
Cost of sales	(3,039)	-	(6,162)	(9,201)
Net impairment (charge)/reversal on oil and gas assets	-	(409,800)	-	(409,800)
Other income	161,908	-	-	161,908
Finance costs	-	-	(39,733)	(39,733)
	147,591	(409,800)	(45,895)	(308,104)
Tax on items above	(58,090)	158,188	15,372	115,470
Derecognition of undiscounted deferred tax asset (restated)(iv)	-	(286,020)	-	(286,020)
	89,501	(537,632)	(30,523)	(478,654)

(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 $37.0 million (2020: $11.3 million). Other income relates to the fair value remeasurement of contingent consideration relating to the acquisition of Magnus and associated infrastructure of $27.5 million (note 10) (2020: $161.9 million)

(ii) Impairments and write offs include an impairment of tangible oil and gas assets totalling nil (note 7) (2020: impairment of $409.8 million)

(iii) Other items mainly relate to unwinding of discount on contingent consideration on the 75% acquisition of Magnus and associated infrastructure of $30.3 million (note 10) (2020: $39.7 million). (2020 also included a redundancy provision in relation to the Group's transformation programme of $6.1 million)

(iv) Non-cash deferred tax charge (2020 restated (see Note 2 Basis of preparation - Restatements) following a reassessment of deferred tax balances reflecting revisions to forecast assumptions.

5. Revenue

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 2021 $'000	Period ended 30 June 2020 $'000
Revenue from contracts with customers:
Revenue from crude oil sales	490,536	375,518
Revenue from gas and condensate sales(i)	57,850	27,574
Tariff revenue	467	7,993
Total revenue from contracts with customers	548,853	411,085
Rental income from vessels⁽ⁱⁱ⁾	702	2,865
Realised (losses)/gains on oil derivative contracts	(32,908)	35,229
Other	1,640	825
Business performance revenue and other operating income	518,287	450,004
Unrealised (losses)/gains on oil derivative contracts(iii)	(36,973)	(11,278)
Total revenue and other operating income	481,314	438,726

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

(ii) Comparative information for 2020 has been restated for the changes to the presentation of rental income effective 1 January 2021. For more information, see Note 2 Basis of preparation - Restatements

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

6. Earnings per share

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

Basic and diluted earnings per share are calculated as follows:

	Profit/(loss) after tax			Weighted average number of Ordinary shares				Earnings per share
	Period ended 30 June			Period ended 30 June				Period ended 30 June
	2021 $'000	2020 restated $'000		2021 million	2020 million			2021 $	2020 restated $
Basic	(56,372)		(472,483)	1,649.3		1,654.8	(0.034)			(0.286)
Dilutive potential of Ordinary shares granted under share-based incentive schemes	-		-	26.7		6.9	-			-
Diluted(i)	(56,372)	(472,483)		1,676.0	1,661.7			(0.034)	(0.286)
Basic (excluding remeasurements and exceptional items)⁽ⁱⁱ⁾	108,265	6,216		1,649.3	1,654.8			0.066	0.004
Diluted (excluding remeasurements and exceptional items)(i) ⁽ⁱⁱ⁾	108,265	6,216		1,676.0	1,661.7			0.065	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

(ii) 2020 comparative restated see Note 2 Basis of preparation - Restatements

7. 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 2021	8,552,171	64,220	858,489	9,474,880
Additions	22,734	575	4,669	27,978
Change in decommissioning provision	7,086	-	-	7,086
At 30 June 2021	8,581,991	64,795	863,158	9,509,944
Accumulated depreciation, depletion and impairment:
At 1 January 2021	6,428,559	50,357	362,047	6,840,963
Charge for the year	122,877	1,869	32,254	157,000
Other	146	-	-	146
At 31 June 2021	6,551,582	52,226	394,301	6,998,109
Net carrying amount:
At 30 June 2021	2,030,409	12,569	468,857	2,511,835
At 31 December 2020	2,123,612	13,863	496,442	2,633,917
At 30 June 2020	2,263,794	14,723	530,618	2,809,135

There were no impairment reversals or charges in the period.

8. Loans and borrowings

	30 June 2021 $'000	31 December 2020 $'000
Borrowings	367,164	452,284
Bonds	1,088,328	1,045,041
	1,455,492	1,497,325

Borrowings

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

	30 June 2021			31 December 2020
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
Credit facility⁽ⁱ⁾	353,051	-	353,051	377,270	-	377,270
Sculptor Capital facility⁽ⁱⁱ⁾	-	-	-	67,701	(1,925)	65,776
SVT Working Capital facility	14,113	-	14,113	9,238	-	9,238
Reserves based lending ('RBL') facility⁽ⁱⁱⁱ⁾	-	-	-	-	-	-
Total borrowings	367,164	-	367,164	454,209	(1,925)	452,284
Due within one year			367,164			414,430
Due after more than one year			-			37,854
Total borrowings			367,164			452,284

(i) At 30 June 2021, the total carrying amount of the credit facility on the balance sheet was $353.5 million, comprising the loan principal drawn down of $335.0 million, $18.1 million of interest capitalised to the PIK amount and $0.4 million accrued interest (2020: full carrying amount $377.8 million, comprising the loan principal drawn down of $360.0 million, $17.3 million of interest capitalised to the PIK amount and $0.5 million accrued interest). The maturity date of the credit facility was October 2021, with the facility being fully repaid in July 2021 as outlined in note 14. Further details on the credit facility are included in the Group's Annual Report and Accounts 2020.

(ii) During the period, the Group repaid its outstanding debt on the Sculptor Capital facility.

(iii) On 11 June 2021, the Group signed a new RBL facility of approximately $600 million and an additional amount of $150 million for letters of credit for up to seven years. Upon refinancing of the Group's existing high yield bonds, the maturity of the new facility is extended to the earlier of seven years from its signing date, or the point at which the remaining economic reserves for all borrowing base assets are projected to fall below 25% of the initial economic reserves forecast. In the event the maturity of the new facility is not extended, any amounts drawn amortise such that they are fully repaid by June 2023. As at 30 June 2021, the facility was undrawn. Transaction costs in relation to the new facility have been deferred within other long term assets on the balance sheet and will be reclassified to borrowings upon drawdown of the facility. For further details of the new RBL see note 14.

Bonds

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

	30 June 2021			31 December 2020
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
High yield bond⁽ⁱ⁾	827,166	(2,196)	824,970	799,194	(2,666)	796,528
Retail bond⁽ⁱⁱ⁾	263,891	(533)	263,358	249,161	(648)	248,513
Total bonds due after more than one year	1,091,057	(2,729)	1,088,328	1,048,355	(3,314)	1,045,041

(i) The total carrying value of the high yield bond as at 30 June 2021 is $825.0 million (2020: $796.5 million). This includes bond principal of $827.2 million (2020: $799.2 million) less unamortised fees of $2.2 million (2020: $2.7 million). The high yield bond does not include accrued interest of $12.1 million (2020: $11.8 million) and liability for the IFRS 9 Financial Instruments loss on modification of $4.6 million (2020: $4.6 million), which are reported within trade and other payables.

(ii) The total carrying value of the retail bond as at 30 June 2021 is $263.4 million (2020: $248.5 million). This includes bond principal of $263.9 million (2020: $249.2 million) less unamortised fees of $0.5 million (2020: $0.6 million). The retail bond does not include accrued interest of $6.8 million (2020: $6.3 million) and liability for the IFRS 9 Financial Instruments loss on modification of $11.9 million (2020: $11.9 million), which are reported within trade and other payables.

9. Other financial assets and financial liabilities

(a) Summary as at 30 June 2021

	30 June 2021		31 December 2020
	Assets $'000	Liabilities $'000	Assets $'000	Liabilities $'000
Fair value through profit or loss:
Derivative commodity contracts	-	38,980	-	2,007
Derivative foreign exchange contracts	-	-	-	-
Total current	-	38,980	-	2,007
Fair value through profit or loss:
Quoted equity shares	6	-	7	-
Amortised cost:
Other receivables ⁽ⁱ⁾	34,811	-	-	-
Total non-current	34,817	-	7	-

(i) Transaction costs of $34.8m in relation to the Golden Eagle asset acquisition, refinancing and equity raise have been deferred within other long term assets on the balance sheet. The balance will be reclassified to the following line items upon completion of the relevant Golden Eagle transaction components: oil and gas assets, borrowings and equity.

(b) Income statement impact

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

Period ended 30 June 2021	Revenue and other operating income		Cost of sales
Period ended 30 June 2021	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	(28,600)	(35,786)	-	-
Commodity swaps	(3,610)	(1,187)	-	-
Commodity futures	1,693	-	-	-
Carbon forwards	-	-	8,157	-
	(30,517)	(36,973)	8,157	-

Period ended 30 June 2020	Revenue and other operating income		Cost of sales
Period ended 30 June 2020	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	20,711	4,972	-	-
Commodity swaps	9,556	(16,223)	-	-
Commodity futures	4,962	(27)	-	-
Foreign exchange contracts	-	-	(528)	(3,039)
	35,229	(11,278)	(528)	(3,039)

30 June 2021	Total $'000	Quoted prices in active markets (Level 1) $'000	Significant observable inputs (Level 2) $'000	Significant unobservable inputs (Level 3) $'000
Financial assets measured at fair value:
Other financial assets at FVPL
Quoted equity shares	6	6	-	-
Liabilities measured at fair value:
Derivative financial liabilities at FVPL
Oil commodity derivative contracts	38,980	-	38,980	-
Other financial liabilities measured at FVPL
Contingent consideration	508,765	-	-	508,765
Liabilities measured at amortised cost for which fair values are disclosed below:
Interest-bearing loans and borrowings	367,164	-	-	367,164
Obligations under leases	620,140	-	-	620,140
Retail bond	322,819	322,819	-	-
High yield bond	775,468	775,468	-	-

31 December 2020	Total $'000	Quoted prices in active markets (Level 1) $'000	Significant observable inputs (Level 2) $'000	Significant unobservable inputs (Level 3) $'000
Financial assets measured at fair value:
Other financial assets at FVPL
Quoted equity shares	7	7	-	-
Liabilities measured at fair value:
Derivative financial liabilities at FVPL
Oil commodity derivative contracts	2,007	-	2,007	-
Other financial liabilities measured at FVPL
Contingent consideration	522,261	-	-	522,261
Liabilities measured at amortised cost for which fair values are disclosed below:
Interest-bearing loans and borrowings	454,209	-	-	454,209
Obligations under leases	647,846	-	-	647,846
Retail bond	225,943	225,943	-	-
High yield bond	537,602	537,602	-	-

Fair value hierarchy

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

Level 1: Quoted (unadjusted) market prices in active markets for identical assets or liabilities;

Level 2: Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly (i.e. as prices) or indirectly (i.e. derived from prices) observable;

Level 3: Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable.

Derivative financial instruments are valued by counterparties, with the valuations reviewed internally and corroborated with readily available market data (Level 2). Contingent consideration is measured at FVPL using the Level 3 valuation processes disclosed in note 10. There have been no transfers between Level 1 and Level 2 during the period (2020: no transfers).

For the financial 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 that financial instrument. Interest-bearing loans and borrowings and obligations under finance leases were calculated using the discounted cash flow method to capture the present value (Level 3).

10. Contingent consideration

	Magnus 75% $'000	Magnus decommissioning-linked liability $'000	Total $'000
At 31 December 2020	507,660	14,601	522,261
Change in fair value	(28,685)	1,195	(27,490)
Unwinding of discount	24,778	729	25,507
Interest on vendor loan	4,792	-	4,792
Utilisation	(16,028)	(277)	(16,305)
At 30 June 2021	492,517	16,248	508,765
Classified as:
Current	65,119	809	65,928
Non-current	427,398	15,439	442,837
	492,517	16,248	508,765

75% Magnus acquisition contingent consideration

The contingent consideration was fair valued at 30 June 2021, which resulted in a decrease in fair value of $28.7 million reflecting a change in the payment profiles (2020: decrease of $159.5 million reflecting the change in oil price assumptions). The fair value accounting effect and finance costs of $29.6 million (2020: $38.9 million) on the contingent consideration were recognised through remeasurements and exceptional items in the Group income statement. The contingent profit sharing arrangement cap of $1 billion was not met as at 30 June 2021 in the present value calculations (2020: cap was not met). Within the statement of cash flows: the profit share element of the repayment, $1.0 million (2020: $21.1 million), is disclosed separately under investing activities; the repayment of the vendor loan, $11.4 million (2020: $4.7 million), is disclosed under financing activities; and the interest paid on the vendor loan, $3.6 million (2020: $3.1 million), is included within interest paid under financing activities. At 30 June 2021, the contingent consideration was $492.5 million (31 December 2020: $507.7 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 2021, the amount due to BP calculated on an after-tax basis by reference to 30% of BP's decommissioning costs on Magnus was $16.2 million (31 December 2020: $14.6 million).

11. Provisions

	Decommissioning provision $'000	Thistle decommissioning provision $'000	Other provisions $'000	Total $'000
At 31 December 2020	778,204	53,066	9,137	840,407
Changes in estimates	13,381	(577)	(271)	12,533
Unwinding of discount	7,928	531	-	8,459
Utilisation	(31,066)	(13,887)	(4,201)	(49,154)
Foreign exchange	-	197	(144)	53
At 30 June 2021	768,447	39,330	4,521	812,298
Classified as:
Current	56,307	9,532	4,521	70,360
Non-current	712,140	29,798	-	741,938
	768,447	39,330	4,521	812,298

Decommissioning provision

The Group's total provision represents the present value of decommissioning costs which are expected to be incurred up to 2048, assuming no further development of the Group's assets. At 30 June 2021, an estimated $302.9 million is expected to be utilised between one and five years (31 December 2020: $329.2 million), $148.1 million within six to ten years (31 December 2020: $145.1 million), and the remainder in later periods.

The Group enters into surety bonds principally to provide security for its decommissioning obligations. At 30 June 2021, the Group held surety bonds totalling $164.9 million (31 December 2020: $151.7 million).

Thistle decommissioning provision

At 30 June 2021, the amount due to BP by reference to 7.5% of BP's decommissioning costs on Thistle and Deveron was $39.3 million (31 December 2020: $53.1 million), with the reduction mainly reflecting utilisation in the period. Unwinding of discount of $0.5 million is included within finance income for the year ended 30 June 2021 (2020: $0.4 million).

Other provisions

During 2020, a riser at the Seligi Alpha platform which provides gas lift and injection to the Seligi Bravo platform detached. A provision with respect to required repairs to remedy the damage caused was established. At 30 June 2021, the provision was $4.5 million (31 December 2020: $5.9 million). During the first half of 2021, $1.5 million of the provision was utilised.

Other provisions from 31 December 2020 were fully utilised in the period to 30 June 2021. These included a redundancy provision in relation to the transformation programme undertaken during 2020/2021 (31 December 2020: $1.2 million) and payment of partners' share of pipeline oil stock following cessation of production at Heather (31 December 2020: $1.5 million).

12. Commitments and contingencies

Capital commitments

At 30 June 2021, the Group had capital commitments amounting to nil (31 December 2020: nil).

Other commitments

In the normal course of business, the Group will obtain surety bonds, letters of credit and guarantees. At 30 June 2021, the Group held surety bonds totalling $164.9 million (31 December 2020: $151.7 million) to provide security for its decommissioning obligations. See note 11 for further details.

Contingencies

The Group becomes involved from time to time in various claims and lawsuits arising in the ordinary course of its business. 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 Company's and/or the Group's financial position or profitability, nor, so far as the Group is aware, are any such proceedings pending or threatened.

13. Cash flow information

Cash generated from operations

	Notes	Period ended 30 June 2021 $'000	Period ended 30 June 2020 $'000⁽ⁱ⁾
Profit/(loss) before tax		49,072	(373,357)
Depreciation	7	3,915	3,941
Depletion	7	153,085	248,384
Net impairment charge to oil and gas assets		-	409,800
Net disposal/write down of inventory		983	18,959
Change in fair value of investments		1	8
Share-based payment charge		3,515	2,616
Gain on termination of Tanjong Baram risk service contract		-	(10,412)
Change in contingent consideration		2,810	(122,175)
Change in provisions		14,754	13,676
Amortisation of option premiums		-	(5,587)
Unrealised (gain)/loss on commodity financial instruments		36,973	11,278
Unrealised (gain)/loss on other financial instruments		-	3,039
Unrealised exchange (gain)/loss		4,796	(18,371)
Net finance expense		78,042	82,345
Operating profit before working capital changes		347,946	264,144
Decrease/(increase) in trade and other receivables		(121,006)	51,972
(Decrease)/increase in inventories		470	3,129
(Decrease)/increase in trade and other payables		60,469	(36,685)
Cash generated from operations		287,879	282,560

(i) See Note 2 Basis of preparation - Restatements

Changes in liabilities arising from financing activities

	Loans and borrowings $'000	Bonds $'000	Lease liabilities $'000	Total $'000
At 31 December 2020	(452,774)	(1,079,692)	(647,846)	(2,180,312)
Cash movements:
Repayments of loans and borrowings	88,170	-		88,170
Repayment of lease liabilities			57,286	57,286
Cash interest paid in year	10,000	-		10,000
Non-cash movements:
Additions	-	-	(4,670)	(4,670)
Interest/finance charge payable	(10,836)	(37,521)	(23,532)	(71,889)
Fee amortisation	(1,925)	(585)	-	(2,510)
Foreign exchange adjustments	(344)	(5,182)	(1,377)	(6,903)
Other non-cash movements	139	1	-	140
At 30 June 2021	(367,570)	(1,122,979)	(620,140)	(2,110,689)

Reconciliation of carrying value

	Loans and borrowings $'000	Bonds $'000	Lease liabilities $'000	Total $'000
Principal	(367,164)	(1,091,057)	(620,140)	(2,078,361)
Unamortised fees	-	2,729	-	2,729
Accrued interest	(406)	(34,651)	-	(35,057)
At 30 June 2021	(367,570)	(1,122,979)	(620,140)	(2,110,689)

14. Subsequent events

In July 2021, $360.0 million was drawn down from the new RBL facility and the outstanding debt on the credit facility, as detailed in note 8, was repaid. In addition, $58.7 million, representing the full amount of the outstanding principal and interest on the BP vendor loan, which forms part of the contingent consideration balance as disclosed in note 10, was repaid.

In July 2021, the Group raised gross proceeds of £36.1 million ($50 million) through the issuance of 190,122,384 new ordinary shares at an issue price of 19 pence per ordinary share via a firm placing, placing and open offer.

In July 2021, the Group completed the acquisition of the entire 100% equity interest in the P1078 licence containing the proven Bentley heavy-oil discovery from Whalsay Energy Holdings Limited ('Whalsay'). The transaction was effected through the acquisition of Whalsay's subsidiary, Whalsay Energy Limited ('WEL') which holds the licence as its only asset, on a cash, liability and debt free basis. On completion, consideration of c.$2 million was paid to fund certain accrued costs and obligations of WEL. No other upfront consideration was payable. EnQuest will make deferred payments to Whalsay based on future revenues generated by WEL which are capped at $40 million.

Statement of Directors' Responsibilities

We confirm that to the best of our knowledge:

a) the condensed set of financial statements, which has been prepared in accordance with the applicable set of accounting standards, gives a true and fair view of the assets, liabilities, financial position and profit or loss of the issuer, or the undertakings included in the consolidation as a whole as required by DTR 4.2.4R;

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

Amjad Bseisu

Chief Executive

1 September 2021

Independent review report to EnQuest PLC

We have been engaged by EnQuest PLC ('the Company') to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2021 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 14. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

Directors' Responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, 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.

The annual financial statements of the Group will be prepared in accordance with United Kingdom adopted International Financial Reporting 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".

Our Responsibility

Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 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. 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.

Conclusion

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 2021 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.

Use of Report

This report is made solely to the company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council. 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

1 September 2021

Glossary - Non-GAAP measures

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

Business performance net profit attributable to EnQuest PLC shareholders	Period ended 30 June 2021 $'000	Period ended 30 June 2020 restated $'000
Reported net profit/(loss) (A)⁽ⁱ⁾	(56,372)	(472,438)
Adjustments - remeasurements and exceptional items:
Unrealised (losses)/gains on oil derivative contracts (note 9b)	(36,973)	(11,278)
Unrealised (losses)/gains on foreign exchange derivative contracts (note 9b)	-	(3,039)
Net impairment (charge)/reversal to oil and gas assets (note 4)	-	(409,800)
Unwind and interest on contingent consideration (note 10)	(30,299)	(39,733)
Change in fair value of contingent consideration (note 10)	27,490	161,908
Redundancy provision (note 11)	-	(6,162)
Pre-tax remeasurements and exceptional items (B)	(39,782)	(308,104)
Tax on remeasurements and exceptional items (note 4) (C)⁽ⁱ⁾	(124,855)	(170,550)
Post-tax remeasurements and exceptional items (D = B + C)⁽ⁱ⁾	(164,637)	(478,654)
Business performance net profit attributable to EnQuest PLC shareholders (A - D)	108,265	6,216

(i) 2020 comparatives have been restated see Note 2 Basis of preparation - Restatements

EBITDA	Period ended 30 June 2021 $'000	Period ended 30 June 2020 restated $'000
Reported profit/(loss) from operations before tax and finance income/(costs)	165,872	(243,765)
Adjustments:
Remeasurements and exceptional items	9,483	268,371
Depletion and depreciation (note 7)	157,000	252,325
Inventory revaluation	983	18,959
Change in provision⁽ⁱ⁾	5,718	45,879
Net foreign exchange (gain)/loss	6,360	(20,971)
Business performance EBITDA (E)	345,416	320,798

(i) During the second half of 2020, the Group's definition of EBITDA was changed to exclude the impact of changes in the decommissioning provision of fully impaired assets. Comparative information for 2020 has been updated to reflect this change.

EBITDA is calculated on a 'Business performance' basis, and is calculated by taking profit/(loss) from operations before tax and finance income/(costs) and adding back depletion, depreciation, foreign exchange movements, inventory revaluation, change in provision and the realised gain/(loss) on foreign currency and derivatives related to capital expenditure.

Total cash and available facilities	Period ended 30 June 2021 $'000	Year ended 31 December 2020 $'000
Available cash	173,027	113,185
Ring-fenced cash	71,304	107,970
Restricted cash	30,703	1,675
Total cash and cash equivalents (F)	275,034	222,830

Available credit facilities	410,000	450,000
Credit facility - Drawn down	(335,000)	(360,000)
Letter of credit	(46,629)	(28,778)
Available undrawn facility (G)	28,371	61,222
Total cash and available facilities (F + G)	303,405	284,052

Ring-fenced cash includes joint venture accounts and cash held in operational accounts

Net debt	Period ended 30 June 2021 $'000	Year ended 31 December 2020 $'000
Borrowings (note 8):
Credit facility - Drawn down	335,000	360,000
Credit facility - PIK	18,051	17,270
Sculptor Capital facility	-	65,776
SVT Working Capital facility	14,113	9,238
Borrowings (H)	367,164	452,284
Bonds (note 8):
High yield bond	824,970	796,528
Retail bond	263,358	248,513
Bonds (I)	1,088,328	1,045,041
Non-cash accounting adjustments (note 8):
Unamortised fees on loans and borrowings	-	1,925
Unamortised fees on bonds	2,729	3,314
Non-cash accounting adjustments (J)	2,729	5,239
Debt (H + I + J) (K)	1,458,221	1,502,564
Less: Cash and cash equivalents (E)	275,034	222,830
Net debt/(cash) (K - F) (L)	1,183,187	1,279,734

EnQuest defines net debt as excluding finance lease liabilities of $620.1 million (2020: $647.8 million)

Net debt/EBITDA	Period ended 30 June 2021 $'000	Year ended 31 December 2020 $'000
Net debt (L)	1,183,187	1,279,734
Business performance EBITDA (last 12 months) (E)	575,194	550,606
Net debt/EBITDA (L/E)	2.1	2.3

Cash capital expenditure	Period ended 30 June 2021 $'000	Period ended 30 June 2020 $'000
Reported net cash flows (used in)/from investing activities	(19,807)	(104,691)
Adjustments:
Repayment of Magnus contingent consideration - Profit share	968	21,088
Net cash received on termination of Tanjong Baram risk service contract	-	(17,086)
Deposit for Golden Eagle acquisition	3,000	-
Interest received	(83)	(696)
Cash capital expenditure	(15,922)	(101,385)

Free cash flow	Period ended 30 June 2021 $'000	Period ended 30 June 2020 $'000
Net cash flows from/(used in) operating activities	246,942	274,437
Net cash flows from/(used in) investing activities	(19,807)	(104,691)
Net cash flows from/(used in) financing activities	(173,849)	(201,838)
Adjustments:
Repayment of loans and borrowings	88,170	118,906
Free cash flow	141,456	86,814

Free cash flow is the net change in cash and cash equivalents less net (repayments)/proceeds from loan facilities

Revenue sales	Period ended 30 June 2021 $'000	Period ended 30 June 2020 $'000
Revenue from crude oil sales (note 5) (M)	490,536	375,518
Revenue from gas and condensate sales (note 5) (N)	57,850	27,574
Realised (losses)/gains on oil derivative contracts (note 5) (P)	(32,908)	35,229

Barrels equivalent sales	Period ended 30 June 2021 kboe	Period ended 30 June 2020 kboe
Sales of crude oil (Q)	7,288	9,417
Sales of gas and condensate(i)	1,314	1,923
Total sales (R)	8,602	11,340

(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

2021

$/Boe

Period ended

30 June

2020

$/Boe

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

67.3

39.9

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

62.8

43.6

Operating costs	Period ended 30 June 2021 $'000	Period ended 30 June 2020 $'000
Reported cost of sales	333,262	420,071
Adjustments:
Remeasurements and exceptional items	-	(9,201)
Depletion of oil and gas assets	(153,085)	(248,384)
Credit/(charge) relating to the Group's lifting position and inventory	26,060	48,535
Other cost of sales	(53,137)	(36,755)
Operating costs	153,100	174,266
Less realised (gain)/loss on derivative contracts	(8,157)	528
Operating costs directly attributable to production	161,257	173,738
Comprising of:
Production costs (S)	139,537	137,650
Tariff and transportation expenses (T)	21,720	36,088
Operating costs directly attributable to production	161,257	173,738

Barrels equivalent produced

Period ended

30 June

2021

kboe

Period ended

30 June

2020

kboe

Total produced (working interest) (U)

8,360

12,022

Unit opex	Period ended 30 June 2021 $/Boe	Period ended 30 June 2020 $/Boe
Production costs (S/U)	16.7	11.4
Tariff and transportation expenses (T/U)	2.6	3.0
Total unit opex ((S + T)/U)	19.3	14.4

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