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

 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

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:

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:

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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.

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).

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

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:

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:

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:

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.