Results for the year ended 31 December 2021

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Results for the year ended 31 December 2021 - Enquest PLC | RNS | Ticker

RNS Number : 8360F

EnQuest PLC

24 March 2022

EnQuest PLC

Results for the year ended 31 December 2021 and 2022 outlook

24 March 2022

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

Comparative figures for the Income Statement relate to the period ended 31 December 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:

"We made good progress against our strategic objectives in 2021, concluding three acquisitions, refinancing our senior secured debt facility, generating significant free cash flow of $396.8 million and reducing our year end net debt to $1,222.0 million, its lowest level since 2014. We have made strong progress on emissions reduction, which continues to be a focus for the Group.

"We have also started 2022 well, with production to the end of February averaging 50,408 Boepd, towards the top end of our full year guidance range. We have also continued to reduce our net debt, down to $1,090.0 million at the end of February, in line with our strategic priorities. With a supportive oil price environment and an active programme of nine wells and seven workovers in 2022, our largest sanctioned programme since 2014 and our first new wells in over two years, we remain confident on delivering a good performance this year.

"The acquisition of Golden Eagle has strengthened our portfolio, building on our track record of value creation through innovative, disciplined M&A. The acquisitions of Bressay and Bentley have added almost 250 MMboe of 2C resources, adding to those already in place at Magnus, Kraken, PM8/Seligi and PM409, providing EnQuest with longer-term potential development opportunities.

"We remain focused on continuing to reduce our net debt while selectively investing in our low-cost, quick payback well portfolio in order to sustain our production base.

"EnQuest's business is strongly positioned to play an important role in the energy transition. We will do so by responsibly optimising production, leveraging existing infrastructure, delivering decommissioning and exploring new energy and decarbonisation opportunities."

2021 performance

∙	Group net production averaged 44,415 Boepd¹ (2020: 59,116 Boepd)
∙	Revenue and other operating income of $1,320.3 million (2020: $855.1 million) and adjusted EBITDA of $742.9 million (2020: $550.6 million) reflects materially higher oil prices, partially offset by lower production
∙	Cash generated from operations was $756.9 million (2020: $567.2 million)
∙	Cash expenditures of $117.6 million (2020: $173.0 million); cash capital expenditure of $51.8 million (2020: $131.4 million) and cash abandonment expenditure of $65.8 million (2020: $41.6 million)
∙	Strong free cash flow generation² of $396.8 million (2020: $210.5 million)
∙	Cash and available facilities amounted to $318.7 million at 31 December 2021 (2020: $284.1 million), with net debt reduced to $1,222.0 million (2020: $1,279.7 million)
∙	Statutory reported profit after tax was $377.0 million (2020 (restated): loss after tax of $469.9 million)

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

²Net change in cash and cash equivalents less net (repayments)/proceeds from loan facilities, acquisition costs ($258.6 million), the accelerated repayment of the BP vendor loan ($58.7 million) and net proceeds from the firm placing, placing and open offer ($47.2 million)

Significant business development

∙	Successfully completed the acquisition of a 26.69% non-operated interest in the producing Golden Eagle area in October, for an initial consideration of $325.0 million; a highly cash generative asset providing significant value enhancement through the addition of c.18 MMbbls to year end 2021 net 2P reserves and c.3 MMbbls to net 2C resources
∙	Completed purchase of 40.81% equity interest in the Bressay heavy-oil field for an initial consideration of £2.2 million, adding c.115 MMbbls of net 2C resources
∙	Completed purchase of 100.0% equity interest in the P1078 licence containing the proven Bentley heavy-oil discovery, adding c.131 MMbbls of 2C resources

Board changes

∙	Jonathan Swinney has notified the Board of his intention to step down from the Board as Chief Financial Officer and Executive Director at a date to be determined in due course (see separate announcement)

2022 performance and outlook

∙	Year to date February production averaged 50,408 Boepd, in line with full year guidance
∙	Net debt amounted to $1,090.0 million at 28 February
∙	Hedges in place for c.8.6 MMbbls of oil with an average floor price of c.$63/bbl and an average ceiling price of c.$78/bbl
∙	Full year average net Group production expected to be between 44,000 and 51,000 Boepd
∙	Full year operating costs of c.$430 million
∙	Cash capital expenditure of c.$165 million, with cash abandonment expenditure of c.$75 million

Production and financial information

Business performance measures	2021	2020	Change %
Production (Boepd)	44,415	59,116	(24.9)
Revenue and other operating income ($m)^1,2	1,320.3	855.1	54.4
Realised oil price ($/bbl)^1,3	68.6	41.3	66.1
Average unit operating costs ($/Boe)³	20.5	15.2	34.9
Adjusted EBITDA ($m)³	742.9	550.6	34.9
Cash expenditures ($m)	117.6	173.0	(32.0)
Capital³	51.8	131.4	(60.6)
Abandonment	65.8	41.6	58.2
Free cash flow ($m)^{2, 3}	396.8	210.5	88.5
	2021	2020
Net (debt)/cash ($m)³	(1,222.0)	(1,279.7)	(4.5)

Statutory measures	2021	2020	Change %
Reported revenue and other operating income ($m)^2,4	1,265.8	863.9	46.5
Reported gross profit ($m)	358.2	64.8	452.8
Reported profit/(loss) after tax ($m)²	377.0	(469.9)	-
Reported basic earnings/(loss) per share (cents)²	21.7	(29.0)	-
Cash generated from operations ($m)²	756.9	567.2	33.4
Net increase/(decrease) in cash and cash equivalents² ($m)	67.4	(0.2)	-

Notes:

¹ Including realised losses of $67.7 million (2020: realised losses of $6.1 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 66. Cash capital expenditure includes $13.2 million associated with the PM8/Seligi riser replacement

Note, EnQuest defines net debt as excluding finance lease liabilities

⁴ Including net realised and unrealised losses of $122.2 million (2020: net realised and unrealised gains of $2.7 million) associated with EnQuest's oil price hedges

Production details

Average daily production on a net working interest basis	1 Jan 2021 to 31 Dec 2021	1 Jan 2020 to 31 Dec 2020
	(Boepd)	(Boepd)
UK Upstream
- Magnus	11,870	17,416
- Kraken	21,964	26,450
- Golden Eagle¹	1,701	-
- Other Upstream²	3,685	6,468
UK Upstream	39,220	50,334
UK Decommissioning³	167	2,346
Total UK	39,387	52,680
Total Malaysia	5,028	6,436
Total EnQuest	44,415	59,116

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

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

³UK Decommissioning: the Dons, Alma/Galia

2021 performance summary

During the year, EnQuest strengthened its portfolio through the Golden Eagle acquisition and, supported by an improving oil price environment, generated material free cash flow enabling the Group to simplify its balance sheet and further reduce net debt. The Group also made good progress on its decommissioning programmes, significantly reduced Scope 1 and 2 CO₂ equivalent emissions and established an Infrastructure and New Energy business to explore renewable energy and decarbonisation opportunities.

Production of 44,415 Boepd reflected a strong performance at Kraken and the contribution from Golden Eagle following completion of the acquisition, offset by topside and well integrity related outages at Magnus, planned maintenance and a subsea power umbilical failure at the Greater Kittiwake Area ('GKA') and expected natural declines across the portfolio. The natural declines were to a large extent a consequence of the necessary pause in the Group's drilling programme following materially lower oil prices experienced in 2020 and into 2021.

Adjusted EBITDA, cash generated by operations and free cash flow were $742.9 million, $756.9 million and $396.8 million, respectively, with the material increase from 2020 primarily reflecting higher market prices. Cash capital and abandonment expenditures totalled $117.6 million Capital expenditure of $51.8 million primarily reflected the Magnus production enhancement campaign and the PM8/Seligi riser replacement. Cash abandonment expenditure of $65.8 million was focused on decommissioning activities at Heather, Thistle and the Dons.

Liquidity and net debt

At 31 December 2021, net debt was $1,222.0 million, down $57.7 million from $1,279.7 million at 31 December 2020 with a net debt to adjusted EBITDA ratio of 1.6x. Strong free cash flow generation of $396.8 million enabled the payment of $249.7 million cash consideration for the Golden Eagle acquisition and repayment of the BP vendor loan and Sculptor Capital facility, simplifying the Group's debt structure. During the year, EnQuest successfully refinanced its senior credit facility ('RCF') into a new senior secured debt facility ('RBL') of up to $750.0 million. The strong free cash flow generation also resulted in a lower than expected drawdown on the Group's RBL facility, and facilitated an early voluntary repayment of $70.0 million prior to the year end. At the end of December, the RBL facility was drawn to $415.0 million. Total cash and available facilities were $318.7 million, including restricted funds and ring-fenced funds held in joint venture operational accounts totalling $191.4 million.

As at 28 February 2022, net debt was $1,090.0 million, down a further $132.0 million from 31 December 2021, reflecting strong free cash flow and positive working capital movements. As at the date of this announcement, the Group had made further early voluntary repayments of its RBL facility totalling $85.3 million, with the amount drawn down reduced to $329.7 million. EnQuest is targeting progress towards a net debt to adjusted EBITDA ratio of 0.5x.

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 115 MMbbls (net) 2C resources. 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 July 2021, the Group completed the acquisition of the 100.00% equity interest in the P1078 licence containing the proven Bentley heavy-oil discovery from Whalsay Energy Holdings Limited ('WEL'). This discovery, which has added 131 MMboe (net) 2C resources, 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, EnQuest funded certain accrued costs and obligations of WEL, which amounted to less than $2.0 million.

In October 2021, the Group completed the acquisition of a 26.69% non-operated interest in the producing Golden Eagle area from Suncor Energy UK, for an initial consideration of $325.0 million. The transaction has added 18 MMboe to net 2P reserves.

Reserves and resources

Net 2P reserves at the end of 2020 were c.194 MMboe (2020: c.189 MMboe) and have been audited on a consistent basis with prior years. During the year, the Group produced 8.2% of its year-end 2020 2P reserves base but this was more than offset by the acquisition of Golden Eagle, which resulted in an addition of c.18 MMboe. Net 2C resources were c.402 MMboe (2020: c.164 MMboe), an increase of 145.1% compared to the end of 2020 primarily as a result of the acquisitions of equity interests in the Bressay field and Bentley discovery, which combined added 246 MMboe.

Environmental, Social and Governance

The Group has made excellent progress in reducing its absolute Scope 1 and 2 emissions during the year, with CO₂ equivalent emissions reduced by 14.7%, reflecting operational improvements and increased workforce awareness driving lower flaring, fuel gas and diesel usage. Since 2018, UK Scope 1 and 2 emissions have reduced by 43.5%, which is significantly ahead of the UK Government's North Sea Transition Deal target of achieving a 10% reduction in Scope 1 and 2 CO₂ equivalent emissions by 2025 and close to the 50% reduction targeted by 2030.

The health, safety and wellbeing of our employees is our top priority. Despite the challenges and uncertainties of 2021, the Group's Lost Time Incident ('LTI') performance remained relatively stable with a Group LTI frequency¹ of 0.21 (2020: 0.22), slightly better than the International Association of Oil and Gas Producers benchmark of 0.22.

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

With respect to COVID-19, 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 and level of risk. The changes in general infection rates and associated modifications to processes and controls impacted the execution and cost of some planned activities in 2021. In Malaysia, extended quarantine rules led to significant changes to working rotas and additional costs related to testing and standby rates, while several workscopes were adversely affected by COVID-related impacts on the supply chain. Magnus suffered a seven-day shutdown due to key control room personnel being unavailable due to COVID. The Group is cognisant of the ongoing risks presented by the evolving situation, but at the time of this publication, day-to-day operations in 2022 have not been materially affected.

In February 2021, 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.

In January 2022, Rani Koya was appointed to the Board as a Non-Executive Director and member of the Technical and Reserves Committee. Rani has worked extensively in major energy companies in a variety of technical, project management and executive management roles across the globe. She is currently the CEO of a renewable energy company.

Jonathan Swinney has notified the Board of his intention to step down from the Board as Chief Financial Officer ('CFO') and Executive Director at a date to be determined in due course. Salman Malik, currently Managing Director - Corporate Development, Infrastructure and New Energy and a member of the Group's Executive Committee, will succeed Jonathan as CFO and as an Executive Director upon Jonathan's departure.

Philip Holland, currently Chairman of the Safety, Climate and Risk Committee, will be stepping down as a Director at the Company's 2022 Annual General Meeting. Liv Monica Stubholt will replace Philip as Chair of the Committee in May 2022.

2022 performance and outlook

Group net production averaged 50,408 Boepd for the year to date February. For the full year, the Group's net production is expected to be between 44,000 and 51,000 Boepd. The infill drilling and workover campaigns at Magnus, Golden Eagle and PM8/Seligi are expected largely to mitigate natural declines at these fields. At PM8/Seligi, the outlook is positive with the acceleration of securing a dive support vessel resulting in the riser being connected ahead of schedule and all the wells now onstream. Extensive maintenance shutdowns are also planned at both Magnus and Kraken. Kraken gross production is expected to be between 22,000 Boepd and 26,000 Boepd (15,500 Boepd to 18,500 Boepd net), reflecting the planned shutdown and natural decline.

At current foreign exchange rates and oil prices, operating costs are expected to be approximately $430 million. The increase versus 2021 includes a full year of Golden Eagle operating costs, planned well workover activities in Malaysia, an enhanced maintenance programme on Magnus and significantly increased emissions and diesel costs as a result of higher market prices.

Cash capital expenditure is expected to be around $165 million, primarily relating to drilling campaigns at Magnus (three wells), Golden Eagle (two wells) and in Malaysia (four wells), as well as preparatory activities ahead of future drilling at Kraken. Abandonment expense is expected to total approximately $75 million, primarily reflecting well P&A decommissioning programmes at the Heather/Broom and Thistle/Deveron fields.

EnQuest has hedged a total of 8.6 MMbbls for 2022 primarily using costless collars, with an average floor price of c.$63/bbl and an average ceiling price of c.$78/bbl. For 2023, the Group has hedged a total of 3.5 MMbbls with an average floor price of c.$57/bbl and an average ceiling of c.$77/bbl.

The Group continues to explore options to refinance its Retail and High Yield Bonds ahead of maturity in October 2023.

Summary financial review of 2021

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

The Group made good progress on its strategic aims during 2021. Supported by higher oil prices and capital discipline, EnQuest generated strong free cash flow of $396.8 million, up 88.5% compared to 2020, which, along with the signing of a new senior secured credit facility ('RBL'), enabled the Group to simplify its capital structure, facilitate the Golden Eagle acquisition and reduce overall net debt.

Revenue for 2021 was $1,320.3 million, 54.4% higher than in 2020 ($855.1 million) reflecting the materially higher realised prices partially offset by lower volumes. Revenue is predominantly derived from crude oil sales, which totalled $1,139.2 million, 46.1% higher than in 2020 ($779.9 million), reflecting the significantly higher oil prices, offset by lower production. Revenue from the sale of condensate and gas, primarily in relation to the onward sale of third-party gas purchases not required for injection activities at Magnus, was $244.1 million (2020: $60.5 million), as a result of the significantly higher gas prices.

The Group's commodity hedge programme resulted in realised losses of $67.7 million in 2021 (2020: losses of $6.1 million). The Group's average realised oil price excluding the impact of hedging was $73.0/bbl, 75.5% higher than in 2020 ($41.6/bbl). The Group's average realised oil price including the impact of hedging was $68.6/bbl in 2021, 66.4% higher than 2020 ($41.3/bbl).

Total cost of sales were $900.4 million for the year ended 31 December 2021, 14.6% higher than in 2020 ($785.5 million).

The Group's operating costs decreased by $7.6 million to $321.0 million (2020: $328.6 million), primarily reflecting reduced tariff and transportation costs due to lower production and realised derivative gains related to emissions allowances. This was largely offset by higher production costs driven by materially higher emission allowances costs, lower lease charter credits reflecting higher uptime at Kraken driven by the continued strong performance of the FPSO and remediation costs at Magnus. Unit operating costs (excluding hedging) increased by 34.9% to $20.5/Boe (2020: $15.2/Boe), reflecting lower production. Unit operating costs including hedging were $19.8/Boe (2020: $15.2/Boe).

Total cost of sales also included non-cash depletion expense of $305.6 million, 30.3% lower than in 2020 ($438.2 million), mainly reflecting lower production.

The charge relating to the Group's lifting position and inventory was $62.3 million (2020: credit of $34.8 million). This reflects a switch to an $18.0 million net overlift position at 31 December 2021 from a $3.0 million net underlift position at 31 December 2020. The charge for the year is also impacted by the post-acquisition revaluation of the Golden Eagle underlift position.

Other cost of operations of $211.5 million were materially higher than in 2020 ($53.5 million), principally as a result of higher Magnus-related third-party gas purchases following the increase in associated market prices, offset by a partial release of the inventory provision.

Adjusted EBITDA for 2021 was $742.9 million, up 34.9% compared to 2020 ($550.6 million), primarily as a result of higher revenue.

The tax charge for 2021 of $53.7 million (2020: $172.5 million tax credit), excluding remeasurements and exceptional items, is mainly due to the taxable profits generated in the year exceeding the Ring Fence Expenditure Supplement ('RFES') on UK activities generated in the year. UK North Sea corporate tax losses at the end of the year decreased to $3,011.0 million (2020: $3,183.9 million).

Remeasurements and exceptional items resulting in a post-tax net gain of $156.7 million have been disclosed separately for the year ended 31 December 2021 (2020: loss of $443.8 million). Revenue included unrealised losses of $54.5 million in respect of the mark-to-market movement on the Group's commodity contracts (2020: unrealised gains of $8.8 million). Other income included a $140.1 million gain in relation to the fair value recalculation of the Magnus contingent consideration reflecting a forecast reduction in Magnus future cash flows (2020: $138.2 million gain). Other finance costs mainly relate to the unwinding of contingent consideration from the acquisition of Magnus and associated infrastructure and interest charged on the vendor loan of $58.4 million (2020: $77.3 million).

The Group's reported cash generated from operations for 2021 was $756.9 million (2020: $567.2 million), primarily as a result of higher revenue. Free cash flow for 2021 was $396.8 million (2020: $210.5million).

Net debt decreased by $57.7 million to $1,222.0 million at 31 December 2021 (31 December 2020: $1,279.7 million). This includes $225.0 million of payment in kind ('PIK') interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing (31 December 2020: $205.8 million).

In June, the Group announced that it had signed a new RBL of $600.0 million with an additional amount of $150.0 million for letters of credit for up to seven years, subject to the timing of the refinancing of the bonds. Also in June, the Group repaid the outstanding principal and interest on the Sculptor Capital facility from free cash flow.

In July 2021, $360.0 million was drawn down from the Group's new RBL 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. Also in July, $58.7 million, representing the full amount of the outstanding principal and interest on the Magnus vendor loan, was repaid and the Group successfully completed an equity raise consisting of net proceeds of $47.2 million.

In October 2021 and following shareholder approval of the Golden Eagle acquisition, a further $125.0 million was drawn down against the RBL to partially fund the $249.7 million cash consideration with the acquisition completing on 22 October 2021. In December 2021, EnQuest made a voluntary early repayment of $70.0 million on the RBL and with further early voluntary repayments totalling $85.3 million made in the first quarter of 2022.

- 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)
Craig Baxter (Senior Investor Relations & Communications Manager)

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

Presentation to Analysts and Investors
A presentation to analysts and investors will be held at 09.30 today - London time. The presentation will be accessible via a webcast by clicking here. A conference call facility will also be available at 09.30 on the following numbers:

Conference call details:

UK: +44 (0) 800 279 6619

International: +44 (0) 207 192 8338

Confirmation Code: 3308419

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.

Chief Executive's report

Overview

We continued to make good progress against our strategic objectives of deliver, de-lever and grow. The acquisition of the Golden Eagle asset has further strengthened our portfolio, while the low-cost acquisitions of material resources at Bressay and Bentley provide us with future near-field development opportunities that can utilise our heavy oil expertise and differential capability in subsea drilling and tie-backs. Production in the year was primarily impacted by a combination of well and topside integrity-related outages at Magnus and natural declines across the portfolio. At Kraken, the floating production, storage and offloading vessel continued to perform well and production at PM8/Seligi was in line with expectations. We demonstrated our decommissioning project capability with significant levels of activity throughout 2021 and have established an Infrastructure and New Energy business with overall responsibility for advancing renewable energy and decarbonisation opportunities. During 2021, the Group also made excellent progress in reducing its absolute Scope 1 and 2 emissions, with CO2 equivalent emissions reduced by 14.7%. Since 2018, UK Scope 1 and 2 emissions have been reduced by 43.5%, which is significantly ahead of the UK Government's near-term North Sea Transition Deal targets.

As always, the safety of EnQuest's people and assets remained an absolute priority. I was particularly pleased to see the Group's Lost Time Incident ('LTI') performance remained 'top quartile' with a Group LTI frequency1 of 0.21.

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

We also continued to evolve our approach to managing COVID-19 to keep our people safe. However, we received a number of improvement notices from the UK Health & Safety Executive ('HSE') relating to our Magnus and SVT operations. We continue to improve further our process safety arrangements and all notices have been or will be fully complied with in accordance with the agreed activity set and timetable.

2021 also saw strong demand for oil which, when combined with supply-side constraints, led to oil prices recovering strongly. The Group's average realised oil price in 2021, including the impact of its commodity hedge programme, was $68.6/bbl, up 66.4% from $41.3/bbl in 2020. This improved commodity price environment enabled the Group to generate strong free cash flow of $396.8 million, an increase of $186.3 million from 2020, and lower net debt to $1,222.0 million, its lowest level since 2014.

Operational performance

EnQuest's average production decreased by 24.9% to 44,415 Boepd, primarily driven by topside and well integrity related outages at Magnus and expected natural declines across the portfolio, partially offset by the contribution from Golden Eagle following completion of the acquisition on 22 October 2021. The natural declines were to a large extent a consequence of the necessary pause in the Group's drilling programme following materially lower oil prices experienced in 2020 and into 2021.

Kraken continued to perform well, delivering top quartile production efficiency of 88% and gross production in line with guidance. During the fourth quarter of 2021, the asset reached the milestone of more than 50 MMbbls (gross) produced since first oil; a great achievement by the combined EnQuest and Bumi Armada team. The 3D seismic gathered during the summer will allow 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. At PM8/Seligi, initial production recovery activities were accelerated, offsetting the delayed riser replacement, while at the Greater Kittiwake Area the power umbilical supporting the Mallard and Gadwall wells was successfully replaced in September, restoring both wells to production. However, production at Magnus was disappointing. Performance was impacted by well integrity and topside issues, an unplanned third-party outage and natural decline. During the year, a production enhancement programme was undertaken, restoring four wells to production, although a compressor gearbox failure in September resulted in single compression train operations for much of the fourth quarter.

During the year, we produced 8.2% of our year-end 2020 2P reserves base. However, with the acquisition of Golden Eagle adding c.18 MMboe at the end of 2021, the Group's 2P reserves at the end the year were around 194 MMboe, marginally higher than the c.189 MMboe at the end of 2020. Following the acquisitions of interests in the Bressay field and the Bentley discovery in the UK, 2C resources increased by 145.1% from the end of 2020 to around 402 MMboe, with both fields each adding more than 100 MMboe of net 2C resources. Other material 2C resources are located at Magnus and Kraken in the UK and PM8/Seligi and PM409, offshore Malaysia.

Following our decisions in 2020 to permanently cease production at several of our highest cost assets, 2021 saw an associated increase in decommissioning activity enabling the Group to demonstrate its decommissioning project capability. Activities were focused on well abandonments at Heather, platform re-habitation and other preparatory activities ahead of the planned well abandonment programme at Thistle, and cessation of production at the Dons field, including the removal of the Northern Producer Floating Production Facility.

In August, the Group established an Infrastructure and New Energy business to support the ongoing transformation of SVT and EnQuest's energy transition ambitions. The new business will focus on strengthening and extending the life of operations and assessing and delivering new energy opportunities over the medium to long term to create a hub of growth in infrastructure and renewables at SVT. Constructive initial engagement with a variety of stakeholders, including potential technical and financial partners, is ongoing.

Financial performance

The Group's adjusted EBITDA and statutory gross profit increased by 34.9% to $742.9 million and 453.0% to $358.2 million, respectively, reflecting the material increase in realised oil prices partially offset by lower production. Operating costs for the year of $321.0 million were slightly lower than 2020, although reflected higher emissions trading scheme costs and additional remediation expenditures at Magnus. Unit operating costs increased to $20.5/Boe primarily reflecting lower production. Cash generated by operations increased to $756.9 million, up 33.4% compared to 2020, with free cash flow generation of $396.8 million.

During the year, we successfully refinanced our previous senior credit facility ('RCF') into a new senior secured debt facility ('RBL') of up to $750.0 million. The strong cash flow performance and refinancing ultimately led to a simplified debt structure, with a lower than expected utilisation of the facility, an early voluntary repayment of $70.0 million, repayments of the BP vendor loan and Sculptor Capital facility, and enabled the payment of $250.0 million cash consideration for the Golden Eagle acquisition.

Environmental, Social and Governance

Environmental

Managing existing assets in a responsible and sustainable manner is a key part of the energy transition. We recognise that industry, alongside other key stakeholders such as governments, regulators and consumers, must contribute to reducing the impact on climate change of carbon-related emissions. We are committed to playing our part in the achievement of national emissions reduction targets, with the Infrastructure and New Energy business having overall responsibility for delivering the Group's emission reduction objectives. As outlined earlier, we have made excellent progress in reducing absolute Scope 1 and 2 emissions during the year and are significantly ahead of the Group's targets and those set by the UK Government's North Sea Transition Deal. We continue to optimise sales of Kraken cargoes directly to the shipping fuel market, avoiding emissions related to refining and helping reduce sulphur emissions in accordance with the IMO 2020 regulations.

EnQuest's Infrastructure and New Energy business is assessing renewable energy and decarbonisation opportunities using the existing infrastructure at the Sullom Voe Terminal. We are working collaboratively with Shetland Island Council, Project ORION and the Net Zero Technology Centre, to better understand how we can contribute further to the industry approach to achieving net-zero, whilst remaining aligned with EnQuest's strategy and Values.

Social - Health and safety

EnQuest's absolute priority has consistently been SAFE Results, no harm to our people and respect for the environment, and there remains a strong safety culture throughout the organisation, clearly evidenced by recording a Group LTI frequency1 of 0.21, an improvement on 2021 and slightly better than the International Association of Oil and Gas Producers benchmark of 0.22. We also continued to reduce the number of reportable hydrocarbon releases in both the UK and Malaysia. The Group-wide asset integrity review has brought additional focus to cost allocation in key risk areas that could impact asset integrity.

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

Social - People

Improving workforce diversity and inclusion ('D&I') across the organisation remains a key focus area for the Group. Good progress has been made with the Group-wide D&I strategy and associated policy now embedded in the overall strategy of the business. The D&I strategy includes several targets to improve female and ethnic minority representation in leadership and executive roles by 2025. A number of initiatives continued throughout the year and I was delighted to see EnQuest nominated as one of three finalists for the 2021 OGUK Diversity & Inclusion Award. Recognition as a finalist has further reinforced our commitment to our strategy and direction of travel in relation to D&I.

Social - Communities

In 2021, we extended the remit of the Remuneration Committee to include social responsibility, covering the Group's external support of charitable works and education initiatives. In Malaysia, we continued to sponsor university students to study STEM-related subjects and supported the 'IChemE' accreditation of the Chemical and Process Engineering programme at the National University of Malaysia. We also sponsored and participated in the programme to replant 380 mangrove trees covering an approximate wetland area of 900m2 within the Kuala Selangor Nature Park. In the UK, local community support included financial contributions to charitable organisations throughout the year and the provision of internship placements in roles from Upstream to Communications to young student engineers connected to the Association for Black and Minority Ethnic Engineers. We also extended our partnership with the University of Bradford's Professor of Practice in Sustainability and Energy Futures within the School of Management, Law and Social Sciences.

2022 performance and outlook

Production performance to the end of February was 50,408 Boepd. Our full year net production guidance of between 44,000 and 51,000 Boepd is underpinned by our largest well programme since 2014, including infill drilling and workover campaigns at Magnus, Golden Eagle and PM8/Seligi which are expected largely to mitigate natural declines at these fields.

With an enlarged portfolio, increased activity set and higher emissions and diesel costs as a result of higher market prices, operating expenditures are expected to be approximately $430 million, while capital expenditure is expected to be around $165 million. Abandonment expense is expected to total approximately $75 million, primarily reflecting well P&A decommissioning programmes at the Heather/Broom and Thistle/Deveron fields.

Longer-term development

EnQuest's business has been strengthened by the acquisition of the Golden Eagle asset which has added significant cash-generating capability to the Group, while the supportive macro environment and higher oil prices provide the opportunity for continued debt reduction while selectively investing in its low-cost, short-cycle, quick payback well portfolio to offset natural declines. The acquisitions of Bressay and Bentley have added almost 250 MMboe of 2C resources, adding to those already in place at Magnus, Kraken, PM8/Seligi and PM409, providing EnQuest with longer-term potential development opportunities. At the same time, the Group will continue to be disciplined with respect to M&A opportunities to grow the business further.

With a focus on short-cycle projects, EnQuest can adjust its capital allocation decisions to match the prevailing oil demand and price environment, balancing debt reduction, the development of its existing portfolio, the acquisition of suitable growth opportunities and returns to shareholders. EnQuest's business is strongly positioned to play an important role in the energy transition by responsibly optimising production, leveraging existing infrastructure, delivering a strong decommissioning performance and exploring new energy and further decarbonisation opportunities.

Operating review

Upstream operations

2021 Group performance summary

UK operations

Magnus

2021 performance summary

Production in 2021 was lower than expected at 11,870 Boepd. Performance was impacted by well integrity issues, topside power and compression failures, third-party infrastructure outages and natural decline. A production enhancement programme was undertaken in the second quarter, including a coil tubing campaign, returning four wells to service. Repairs to a compressor gearbox failure which resulted in single train operations during much of the fourth quarter of 2021 were completed, bringing both trains back into operation.

2022 outlook

A shutdown of around three to four weeks is planned in the third quarter to complete scheduled safety-critical activities along with plant equipment upgrades, while further asset integrity maintenance and plant opportunities will continue to be assessed and implemented throughout the year.

It is anticipated that three wells will be drilled in 2022, largely mitigating natural decline at the field, with a further two wells expected to be drilled during 2023. With 2C resources of c.35 MMboe, Magnus offers the Group significant low-cost, quick pay-back drilling opportunities in the medium term.

Kraken

2021 performance summary

Average gross production was within the Group's guidance range at 31,155 Boepd (21,964 Boepd net). Overall subsurface and well performance was good with aggregate water cut evolution remaining in line with expectations and the Floating, Production, Storage and Offloading ('FPSO') vessel continued to perform well throughout the year, with top quartile production and water injection efficiency at 88% and 89%, respectively. During the first half of the year, a number of opportunistic maintenance activities were successfully undertaken, allowing for the deferral of the planned shutdown to 2022. However, production was impacted by short duration shutdowns related to the repair of a subsea tether, an oil heater failure and natural decline.

During the fourth quarter of 2021, Kraken production reached the milestones of over 50 million barrels (gross) produced since inception and the 100th cargo offload.

The Group continues to optimise Kraken cargo sales into the shipping fuel market with Kraken oil a key component of IMO 2020 compliant low-sulphur fuel oil. As such, the Group has benefited from strong pricing in the market and avoids refining-related emissions.

Near-field drilling and subsea tie-back opportunities continue to be assessed. 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.

2022 outlook

Over the summer, a two-week shutdown is planned to undertake safety-critical maintenance work.

For the full year, Kraken production is expected to be between 22,000 Boepd and 26,000 Boepd (15,500 Boepd to 18,500 Boepd net), reflecting the planned shutdown and natural decline.

Evaluation of the 3D seismic is ongoing. The Group is currently assessing main field side-track drilling opportunities along with further opportunities within the Pembroke and Maureen sands.

Golden Eagle

2021 performance summary

The acquisition of a 26.69% interest in Golden Eagle was completed on 22 October 2021, contributing 1,701 Boepd to EnQuest on an annualised basis (10,220 Boepd on a pro forma basis). This reflected high uptime and continued good well performance following the infill drilling campaign earlier in the year.

2022 outlook

A two-well drilling campaign is scheduled late in the year and preparations are being undertaken for further infill drilling in 2023. The asset offers further development opportunities subsea and platform infill drilling.

Other Upstream assets

2021 performance summary

Production in 2021 averaged 3,685 Boepd, slightly below expectations. At GKA, which includes Scolty/Crathes, the reduction was driven by a planned four-week shutdown, the failure of a power umbilical to the Mallard and Gadwall wells, gas compression outages and natural decline. The power umbilical was successfully replaced as planned in September, restoring Mallard and Gadwall to production.

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

At Bressay, detailed analysis of existing reservoir data and an assessment of potential development options, one of which is a potential tie-back to Kraken, continued with strong partner engagement throughout.

2022 outlook

At GKA, a two-week shutdown is planned during the second quarter, in line with a short shutdown of related infrastructure.

At Alba, the partners expect to begin a continuous 2022-2024 drilling programme during the third quarter of 2022. The first wells from this programme are expected to come online during 2023.

At Bressay, it is expected that a field development plan will be developed during 2022, while at Bentley, initial evaluation of the development potential are due to commence in the first quarter of 2022.

Malaysia operations

2021 performance summary

In Malaysia, average production of 5,028 Boepd was 21.9% lower than 2020. This reduction primarily reflected the continued impacts of the detached riser system at the Seligi Alpha platform and the impact of COVID-19 on the execution of various work scopes, although production was in line with expectations following an acceleration of initial production recovery activities in the early part of the year.

In December, the new riser pipeline was successfully laid on the seabed, although final completions were delayed by the late arrival and subsequent availability of the third-party dive support vessel ('DSV'). The riser pipeline was fully installed and commissioned in the first quarter of 2022.

On Block PM409, an area containing several undeveloped discoveries and situated close to the Group's existing PM8/Seligi PSC hub, geotechnical studies have been completed in preparation for future appraisal drilling.

2022 outlook

A two-week shutdown at Seligi to undertake asset integrity and maintenance activities is planned for the summer, which will help to improve reliability and efficiency at the field.

EnQuest has significant 2P reserves and 2C resources of c.20 MMboe and c.86 MMboe, respectively. With a number of low-cost drilling and workover targets having been identified at PM8/Seligi, the Group is expected to drill four infill wells and four workovers during 2022 and plans an annual drilling and workover programme for a number of years thereafter. The Group continues to assess the opportunity to develop the additional gas resource at PM8/Seligi to meet forecast Malaysian demand. At PM409, a well proposal for drilling in 2023 is being developed for approval by the partnership, while a site survey and other associated preparatory activities will also be undertaken.

Decommissioning

2021 performance summary

Average production of 167 Boepd reflected the decision to cease production at the Dons in March 2021. In April 2021, the Northern Producer Floating Production Facility departed the Dons and was handed back to its owners.

At Heather/Broom, the well plug and abandonment ('P&A') programme continued on schedule, while the topsides decommissioning programme was approved by the Secretary of State and topside removal contractors submitted initial tenders in the fourth quarter.

At Thistle/Deveron, the first phase of the platform re-habitation was successfully completed in June, in line with expectations. The subsea integrity campaign concluded in September and platform reactivation and hydrocarbon removal was completed in October.

The EnQuest Producer FPSO remains in warm stack at Nigg while the Group continues to evaluate options.

2022 outlook

At Heather, the well P&A programme is ongoing, with 16 well abandonments scheduled during the year. The drilling rig at Thistle will shortly be reactivated, with 16 wells also anticipated to be abandoned as part of this year's well P&A programme which is planned to start in April. It is expected that topsides and jacket removal contracts will be awarded for both Heather and Thistle later in 2022.

Following Cessation of Production ('CoP') at Alma/Galia, the Dons and Broom, preparations continue ahead of the anticipated commencement of subsea well P&A and infrastructure removal at all three fields, with the target to be execution-ready by the end of 2023.

Infrastructure and New Energy

To support the ongoing transformation of SVT and EnQuest's energy transition ambitions, the Group established an Infrastructure and New Energy business division in August 2021.

2021 performance summary

At the Sullom Voe Terminal ('SVT') and its related infrastructure, the delivery of safe and reliable performance enabled 99.9% service availability during the year. The Group continued 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.

In pipelines, good progress was 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.

2022 outlook

EnQuest remains focused on maintaining safe and reliable operations at the terminal and in its pipeline operations, with a significant asset integrity programme planned. Working closely with SVT co-owners and other stakeholders, EnQuest is developing cost-effective and efficient plans to prepare and repurpose the site in line with the Group's new energy ambitions. Engagement with a variety of stakeholders, including potential technical and financial partners, Shetland Island Council, Project ORION and the Net Zero Technology Centre is ongoing.

Financial review

All figures quoted are in US Dollars and relate to Business performance unless otherwise stated. Please note the below overview includes restated comparatives. See note 2 for further details.

Production on a working interest basis decreased by 24.9% to 44,415 Boepd, compared to 59,116 Boepd in 2020. High uptime at Kraken, the contribution from Golden Eagle and the accelerated recovery of wells at PM8/Seligi was offset by underperformance at Magnus.

Revenue for 2021 was $1,320.3 million, 54.4% higher than in 2020 ($855.1 million) reflecting the materially higher realised prices partially offset by lower volumes. The Group's commodity hedge programme resulted in realised losses of $67.7 million in 2021 (2020: losses of $6.1 million). See note 27 for further information on the Group's hedging programmes.

The Group's operating expenditures of $321.0 million were marginally lower than 2020 ($328.6 million), although unit operating costs (excluding hedging) increased to $20.5/Boe (2020: $15.2/Boe) reflecting lower production.

Other costs of operations of $211.5 million were materially higher than in 2020 ($53.5 million), principally as a result of higher Magnus-related third-party gas purchases following the increase in associated market prices.

With the Group moving into an overlift position during the year, a charge relating to the Group's lifting position and inventory of $62.3 million was recognised (2020: credit of $34.8 million).

Adjusted EBITDA for 2021 was $742.9 million, up 34.9% compared to 2020 ($550.6 million), primarily as a result of higher revenue.

	2021 $ million	2020 $ million
Profit/(loss) from operations before tax and finance income/(costs)	443.2	(20.0)
Depletion and depreciation	313.1	445.9
Change in provisions	(13.1)	95.2
Change in well inventories	0.1	24.9
Net foreign exchange (gain)/loss	(0.4)	4.6
Adjusted EBITDA	742.9	550.6

EnQuest's net debt decreased by $57.7 million to $1,222.0 million at 31 December 2021 (31 December 2020: $1,279.7 million). This includes $225.0 million of payment in kind ('PIK') interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing (31 December 2020: $205.8 million) (see note 18 for further details).

	Net debt/(cash)1
	31 December 2021 $ million	31 December 2020 $ million
Bonds	1,083.8	1,048.3
Multi-currency revolving credit facility ('RCF')	-	377.3
Sculptor Capital facility	-	67.7
Senior secured debt facility ('RBL')	415.0	-
SVT working capital facility	9.9	9.2
Cash and cash equivalents	(286.7)	(222.8)
Net debt	1,222.0	1,279.7

Note:

1 See reconciliation of net debt within the 'Glossary - Non-GAAP measures' starting on page 66

In October 2021 and following shareholder approval of the Golden Eagle acquisition, a further $125.0 million was drawn down against the RBL, partially to fund the $250.0 million cash consideration.

In December 2021, EnQuest made a voluntary early repayment of $70.0 million on the RBL, with further early voluntary repayments totalling $85.3 million made in the first quarter of 2022.

The Group continues to have unrestricted access to its UK North Sea corporate tax losses, subject only to generating suitable future profits, which at the end of the year decreased to $3,011.0 million (2020: $3,183.9 million). The Group paid cash corporate income tax following the acquisition of Golden Eagle by the Group and on the Malaysian assets, which will continue throughout the life of the Production Sharing Contract. In the current environment, no significant corporation tax or supplementary charge is expected to be paid on UK operational activities for the foreseeable future.

Income statement

Revenue

On average, market prices for crude oil in 2021 were significantly higher than in 2020. The Group's average realised oil price excluding the impact of hedging was $73.0/bbl, 75.5% higher than in 2020 ($41.6/bbl). Revenue is predominantly derived from crude oil sales, which totalled $1,139.2 million, 46.1% higher than in 2020 ($779.9 million), reflecting the significantly higher oil prices, offset by lower production. Revenue from the sale of condensate and gas, primarily in relation to the onward sale of third-party gas purchases not required for injection activities at Magnus, was $244.1 million (2020: $60.5 million), as a result of the significantly higher gas prices. Tariffs and other income generated $4.7 million (2020: $20.8 million). The Group's commodity hedges and other oil derivatives contributed $67.7 million of realised losses (2020: losses of $6.1 million). The Group's average realised oil price including the impact of hedging was $68.6/bbl in 2021, 66.4% higher than 2020 ($41.3/bbl).

Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP measures' starting on page 66

Cost of sales1

	2021 $ million	2020 $ million
Production costs	292.3	265.5
Tariff and transportation expenses	39.4	63.7
Realised (gain)/loss on derivatives related to operating costs	(10.7)	(0.6)
Operating costs	321.0	328.6
(Credit)/charge relating to the Group's lifting position and inventory	62.3	(34.8)
Depletion of oil and gas assets	305.6	438.2
Other cost of operations	211.5	53.5
Cost of sales	900.4	785.5
Unit operating cost2	$/Boe	$/Boe
- Production costs	18.1	12.3
- Tariff and transportation expenses	2.4	2.9
Average unit operating cost	20.5	15.2

Notes:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 66

2 Calculated on a working interest basis

Cost of sales were $900.4 million for the year ended 31 December 2021, 14.6% higher than in 2020 ($785.5 million).

Operating costs decreased by $7.6 million, primarily reflecting reduced tariff and transportation costs due to lower production in 2021. This was largely offset by higher production costs driven by materially higher emission allowances costs, lower lease charter credits reflecting higher uptime at Kraken as a result of the continued strong performance of the FPSO, and remediation costs at Magnus. Unit operating costs (excluding hedging) increased by 34.9% to $20.5/Boe (2020: $15.2/Boe), reflecting lower production. Unit operating costs including hedging were $19.8/Boe (2020: $15.2/Boe).

Other cost of operations of $211.5 million were materially higher than in 2020 ($53.5 million), principally as a result of higher Magnus-related third-party gas purchase cost following the increase in associated market prices, offset by a partial release of the inventory provision.

Other income and expenses

Net other income of $23.7 million (2020: net other expense of $85.3 million) is primarily due to a net decrease of $13.1 million related to the decommissioning provision of the fully impaired non-producing assets.

Finance costs

Finance costs of $169.5 million were 5.7% lower than in 2020 ($179.8 million). This decrease was primarily due to a reduction of $12.6 million in interest charges associated with the Group's loans (2021: $20.2 million; 2020: $32.8 million) and a $4.4 million decrease in bond interest (2021: $69.1 million; 2020: $73.5 million). Other finance costs included lease liability interest of $45.4 million (2020: $50.9 million), $16.9 million on unwinding of discount on decommissioning and other provisions (2020: $15.3 million), $13.6 million amortisation of arrangement fees for financing facilities and bonds, reflecting the accelerated amortisation of the Sculptor Capital facility fees and the fees associated with the Group's RBL facility (2020: $5.4 million) and other financial expenses of $4.3 million (2020: $2.0 million), primarily being the cost for surety bonds to provide security for decommissioning liabilities.

Taxation

The tax charge for 2021 of $53.7 million (2020: $172.5 million tax credit), excluding exceptional items, is mainly due to the taxable profits generated in the year exceeding the Ring Fence Expenditure Supplement ('RFES') on UK activities generated in the year.

Remeasurement and exceptional items

Remeasurements and exceptional items resulting in a post-tax net gain of $156.7 million have been disclosed separately for the year ended 31 December 2021 (2020: loss of $443.8 million).

Revenue included unrealised losses of $54.5 million in respect of the mark-to-market movement on the Group's commodity contracts (2020: unrealised gains of $8.8 million). Cost of sales included expenses of $7.3 million in relation to a provision for a contract dispute with a third-party contractor.

Non-cash net impairment reversal of $39.7 million (2020: $422.5 million charge) on the Group's oil and gas assets arises from an increase in the near and medium-term oil price and updated asset profiles.

Other income included a $140.1 million gain in relation to the fair value recalculation of the Magnus contingent consideration reflecting a forecast reduction in Magnus future cash flows (2020: $138.2 million gain). Other finance costs mainly relate to the unwinding of contingent consideration from the acquisition of Magnus and associated infrastructure and interest charged on the vendor loan of $58.4 million (2020: $77.3 million).

A net tax credit of $78.2 million (2020: charge of $76.4 million) has been presented as exceptional, representing the non-cash recognition of undiscounted deferred tax assets of $104.5 million given the Group's acquisition of Golden Eagle and the Group's higher oil price assumptions, partially offset by the tax impact of the remeasurements and exceptional items. EnQuest continues to have unrestricted access to its UK North Sea corporate tax losses of $3,011.0 million at 31 December 2021, subject only to generating suitable future profits.

IFRS results

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

IFRS revenue reflects Business performance revenue, but it is adjusted for the impact of unrealised movements on derivative commodity contracts. Business performance cost of sales is similarly adjusted for the impact of unrealised movements on derivative contracts, together with various exceptional provisions as noted previously. Taking account of these items, and the other exceptional items included within the Group income statement which are principally related to impairment charges and the change in fair value of contingent consideration payable, the Group's IFRS profit from operations before tax and finance costs was $580.0 million (2020: loss of $310.1 million), IFRS profit before tax was $352.4 million (2020: loss of $566.0 million), and IFRS profit after tax of $377.0 million (2020: loss of $469.9 million).

Earnings per share

The Group's Business performance basic earnings per share was 12.7 cents (2020 loss per share: 1.6 cents) and diluted earnings per share was 12.5 cents (2020 loss per share: 1.6 cents).

The Group's reported basic earnings per share was 21.7 cents (2020 loss per share: 29.0 cents) and reported diluted earnings per share was 21.4 cents (2020 loss per share: 29.0 cents).

Cash flow and liquidity

Net debt at 31 December 2021 amounted to $1,222.0 million, including PIK of $225.0 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	674.1
Cash capital expenditure	(51.8)
Acquisition costs	(258.6)
Repayments on Magnus financing and profit share	(74.7)
Finance lease payments	(136.7)
Net interest and finance costs paid	(62.8)
Non-cash capitalisation of interest	(36.4)
Fees related to the RBL facility	(29.1)
Net equity raise proceeds	47.2
Other movements	(13.5)
Net debt 31 December 20211	(1,222.0)

Note:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 66

The Group's reported net cash flows from operating activities for the year ended 31 December 2021 were $674.1 million, up 29.3% compared to 2020 ($521.4 million). The main drivers for this increase were materially higher oil revenue offset by lower production and increased decommissioning spend.

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

	Year ended 31 December 2021 $ million	Year ended 31 December 2020 $ million
North Sea	35.9	127.0
Malaysia	14.8	4.4
Exploration and evaluation	1.1	-
	51.8	131.4

Cash capital expenditure in 2021 primarily related to Magnus production enhancement campaigns and the PM8/Seligi pipeline replacement.

Balance sheet

The Group's total asset value has increased by $503.0 million to $4,365.6 million at 31 December 2021 (2020: $3,862.6 million), mainly due to the acquisition of Golden Eagle and an increase in trade and other receivables. Net current liabilities have decreased to $333.1 million as at 31 December 2021 (2020: $536.9 million). Included in the Group's net current liabilities are $30.5 million of estimated future obligations where settlement is subject to the financial performance of Magnus (2020: $73.9 million).

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

PP&E has increased by $188.1 million to $2,822.0 million at 31 December 2021 from $2,633.9 million at 31 December 2020 (see note 10). This increase encompasses the Golden Eagle asset acquisition of $386.2 million, other capital additions to PP&E of $80.7 million, and non-cash net impairment reversals of $39.7 million, offset by depletion and depreciation charges of $313.0 million and a net decrease of $2.7 million for changes in estimates for decommissioning and other provisions.

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

	$ million
North Sea	449.5
Malaysia	17.4
	466.9

Trade and other receivables

Trade and other receivables increased by $177.4 million to $296.1 million at 31 December 2021 (2020: $118.7 million). The increase is mainly attributable to the timing of receipts for cargoes lifted in December and the impact of gas prices on accrued gas sales.

Cash and net debt

The Group had $286.7 million of cash and cash equivalents at 31 December 2021 and $1,222.0 million of net debt, including PIK of $225.0 million (2020: $222.8 million, $1,279.7 million and $214.2 million, respectively).

Net debt comprises the following liabilities:

∙	$256.2 million principal outstanding on the £155.0 million retail bond, including interest capitalised as PIK of $47.9 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);
∙	$415.0 million drawn down on the RBL (2020: $377.3 million of the RCF, comprising amounts drawn down of $360.0 million and interest capitalised as PIK of $17.3 million); and
∙	$9.9 million relating to the SVT working capital facility (2020: $9.2 million).

Provisions

The Group's decommissioning provision increased by $57.5 million to $835.7 million at 31 December 2021 (2020: $778.2 million). The movement is due to $119.3 million of additions relating to the Golden Eagle acquisition and $15.9 million unwinding of discount, partially offset by utilisation of $55.6 million for decommissioning carried out in the year and a reduction in estimates of $22.1 million.

Other provisions, including the Thistle decommissioning provision, decreased by $3.0 million in 2021 to $59.2 million (2020: $62.2 million). The Thistle decommissioning provision of $43.9 million (2020: $53.1 million) is in relation to EnQuest's obligation to make payments to BP by reference to 7.5% of BP's decommissioning costs of the Thistle and Deveron fields.

Contingent consideration

The contingent consideration related to the Magnus acquisition decreased by $156.7 million. In 2021, EnQuest paid $75.0 million to BP (2020: $74.0 million), which included the early repayment of the entire $74.7 million outstanding balance (including interest) of the 75% interest vendor loan. A change in fair value estimate credit of $140.1 million (2020: $138.2 million) and finance costs of $58.4 million (2020: $77.3 million) were recognised in the year.

The Group recognised $44.7 million contingent consideration payable associated with the acquisition of Golden Eagle which completed in October 2021. The balance increased to $45.2 million at 31 December 2021.

Income tax

The Group had a net income tax payable of $3.6 million (2020: $5.6 million receivable) related to the net of corporate income tax on Malaysian assets and North Sea Research and Development Expenditure Credits.

Deferred tax

The Group's net deferred tax asset has increased from $653.4 million at 31 December 2020 to $699.6 million at 31 December 2021. This is driven by non-cash recognition of undiscounted deferred tax assets due to increased future taxable profits following the acquisition of Golden Eagle. EnQuest continues to have unrestricted access to its UK corporate tax losses carried forward at 31 December 2021 amounting to $3,011.0 million (31 December 2020: $3,189.9 million), subject only to generating suitable future profits. During the year the Group restated the 2020 deferred tax asset position, see note 2 for further details.

Trade and other payables

Trade and other payables of $420.5 million at 31 December 2021 are $165.4 million higher than at 31 December 2020 ($255.2 million). The full balance of $420.5 million is payable within one year. This increase is driven by the increase in the Group's overlift position and the impact of higher market prices on UK emission allowances and Magnus-related gas purchases.

Financial risk management

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

Going concern disclosure

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

The health, safety and wellbeing of the Group's employees is its top priority and it continues to monitor actively the impact on operations from COVID-19. 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 and level of risk. The Group is cognisant of the ongoing risks presented by the evolving situation. At the time of publication of EnQuest's full-year results, the Group's day-to-day operations continue without being materially affected by COVID-19.

During 2021, the Group signed a new senior secured borrowing base debt facility (the 'RBL') of $600.0 million and an additional amount of $150.0 million for letters of credit for up to seven years, subject to refinancing the Group's existing high yield bonds. The RBL is initially repaid based on an amortisation schedule and via a cash sweep mechanism, whereby any unrestricted cash in excess of $75.0 million is swept to repay outstanding amounts at calendar quarter ends. Application of the amortisation schedule ensures the RBL is fully repaid by June 2023.

Upon refinancing of the Group's High Yield Bond, the maturity of the RBL is extended to seven years from its signing date (11 June 2021), 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.

At 31 December 2021, $415.0 million was drawn on the RBL, with early voluntary repayments of $85.0 million made in the first quarter of 2022.

The Group continues to explore options to refinance its Retail and High Yield Bonds ahead of maturity in October 2023. For the purposes of assessing going concern it is assumed that the refinancing of the bonds occurs outside of the going concern period. However, in the scenario that the Group concluded a successful refinancing of the bonds within the next 12 months, then the going concern basis at the date of release of this report would also be considered appropriate.

The Group's latest approved business plan underpins management's base case ('Base Case') and is in line with the Group's production guidance and uses oil price assumptions of $75.0/bbl for 2022 and $70.0/bbl for 2023, adjusted for hedging activity undertaken.

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 $67.5/bbl for 2022 and $63.0/bbl for 2023;
∙	Production risking of c.5% for 2022 and 2023; and
∙	2.5% increase in operating costs.

The Base Case and Downside Case indicate that the Group is able to operate as a going concern and remain covenant compliant for 12 months from the date of publication of its full-year results. The Directors have also performed reverse stress testing on the Base Case, with the liquidity breakeven price in the going concern period being less than $60.0/bbl in order to maintain a minimum unrestricted cash balance of above $50.0 million across all periods (as required by the RBL).

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

Viability statement

The Directors have assessed the viability of the Group over a three-year period to March 2025. The viability assumptions are consistent with the going concern assessment, with the additional inclusion of an oil price of $70.0/bbl for the remainder of 2023 and 2024, a longer-term price of $60.0/bbl from 2025 and refinancing of both the High Yield and Retail Bonds in the second quarter of 2023. This assessment has taken into account the Group's financial position as at March 2022, its future projections and the Group's principal risks and uncertainties. The Directors' approach to risk management, their assessment of the Group's principal risks and uncertainties, which includes potential impacts from climate change concerns and related regulatory developments, and the actions management are taking to mitigate these risks are outlined on pages 16 to 26. The period of three years is deemed appropriate as it is the time horizon across which management constructs a detailed plan against which business performance is measured and includes the maturation of both its High Yield and Retail bonds. Based on the Group's projections, including refinancing of both the High Yield and Retail bonds, the Directors have a reasonable expectation that the Group can continue in operation and meet its liabilities as they fall due over the period to March 2025.

The Base Case has further been stress tested to understand the impact on the Group's liquidity and financial position of reasonably possible changes in these risks and/or assumptions.

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

Oil price volatility

A decline in oil prices would adversely affect the Group's operations and financial condition. To mitigate oil price volatility, the Directors have hedged a total of 8.6 MMbbls for 2022 primarily using costless collars, with an average floor price of c.$62.6/bbl and an average ceiling price of c.$77.6/bbl. For 2023, the Group has hedged a total of 3.5 MMbbls with an average floor price of c.$57.5/bbl and an average ceiling of c.$77.1/bbl. The Directors, in line with Group policy and the terms of its RBL facility, will continue to pursue hedging at the appropriate time and price.

Access to funding

Prolonged low oil prices, cost increases and production delays or outages could threaten the Group's liquidity and/or ability to refinance the bonds.

The maturity date of the existing $827 million High Yield Bond and the £190 million Retail Bonds (both figures at year end 2021) is October 2023. The application of the current amortisation schedule on the RBL ensures this is fully repaid by June 2023. In assessing viability, the Directors recognise that refinancing would be required at or before the maturity date of the bonds and believe this would be achievable subject to market conditions at that time. Under the Base Case oil price assumptions outlined above, the total amount of the High Yield Bond and Retail Bonds outstanding at October 2023 would be unchanged from year end 2021, as interest is payable in cash if the average of the Daily Brent Oil Prices during the period of six calendar months immediately preceding the 'Cash Payment Condition Determination Date' is equal to or above $65.0/bbl. If oil prices were to be lower than the Group's assumptions, then a refinancing may require asset sales or other financing or funding options.

Notwithstanding the principal risks and uncertainties described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group can continue in operation and meet its commitments as they fall due over the viability period ending March 2025. Accordingly, the Directors therefore support this viability statement.

Risks and uncertainties

Management of risks and uncertainties

Consistent with the Group's purpose, the Board has articulated EnQuest's strategic vision to be the operator of choice for maturing and underdeveloped hydrocarbon assets. EnQuest aims to responsibly optimise production, leverage existing infrastructure, deliver a strong decommissioning

performance and explore new energy and further decarbonisation opportunities. It

is focused on delivering on its targets, driving future growth and managing its capital structure and liquidity.

EnQuest seeks to balance its risk position between investing in activities that can achieve its near-term targets, including those associated with reducing emissions, and those which can drive future growth with the appropriate returns, including any appropriate market opportunities that may present themselves, and the continuing need to remain financially disciplined. This combination drives cost efficiency and cash flow generation, facilitating the continued reduction in the Group's debt.

In pursuit of its strategy, EnQuest has to manage a variety of risks. Accordingly, the Board has established a Risk Management Framework ('RMF') to enhance effective risk management within the following Board-approved overarching statements of risk appetite:

∙	The Group makes investments and manages the asset portfolio against agreed key performance indicators consistent with the strategic objectives of enhancing net cash flow, reducing leverage, reducing emissions, managing costs and diversifying its asset base;
∙	The Group seeks to embed a culture of risk management within the organisation corresponding to the risk appetite which is articulated for each of its principal risks;
∙	The Group seeks to avoid reputational risk by ensuring that its operational and HSEA processes, policies and practices reduce the potential for error and harm to the greatest extent practicable by means of a variety of controls to prevent or mitigate occurrence; and
∙	The Group sets clear tolerances for all material operational risks to minimise overall operational losses, with zero tolerance for criminal conduct.

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

As part of its strategic, business planning and risk processes, the Group considers how a number of macroeconomic themes may influence its principal risks. These are factors which the Group should be cognisant of when developing its strategy. They include, for example, long-term supply and demand trends for oil and gas and renewable energy, developments in technology, demographics, the financial and physical risks associated with climate change and how markets and the regulatory environment may respond, and the decommissioning of infrastructure in the UK North Sea and other mature basins. These themes are relevant to the Group's assessments across a number of its principal risks. The Group will continue to monitor these themes and the relevant developing policy environment at an international and national level, adapting its strategy accordingly. For example, the Group has established an Infrastructure and New Energy business to assess new energy and decarbonisation opportunities, initially focused on using the existing infrastructure at the Sullom Voe Terminal. The Group is also conscious that as an operator of mature producing assets with limited appetite for exploration, it has limited exposure to investments which do not deliver near-term returns and is therefore in a position to adapt and calibrate its exposure to new investments according to developments in relevant markets. This flexibility also ensures the Group has mitigation against the potential impact of 'stranded assets'.

As part of its evolution of the Group's RMF, the Safety, Climate and Risk Committee has refreshed its views on all risk areas faced by the Group (categorising these into a 'Risk Library' of 19 overarching risks). For each risk area, the Committee reviewed 'Risk Bowties' that identified risk causes and impacts and mapped these to preventative and containment controls used to manage the risks to acceptable levels.

The Board, supported by the Audit Committee and the Safety, Climate and Risk Committee, has reviewed the Group's system of risk management and internal control for the period from 1 January 2021 to the date of this report and carried out a robust assessment of the Group's emerging and principal risks and the procedures in place to identify and mitigate these risks. The Board confirms that the Group complies in this respect with the Financial Reporting Council's 'Guidance on Risk Management, Internal Control and Related Financial and Business Reporting'.

Near-term and emerging risks

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

During 2021, work was continued to enhance the integration of these risk registers and automate the process to allow management to understand better the various asset risks and how these ultimately impact on the enterprise-level risk and their associated 'Risk Bowties'. In turn, this ensures that the preventative and containment controls in place for a given risk are reviewed and robust based upon the identified risk profile. It also drives the required prioritisation of deep dives to be undertaken by the Safety, Climate and Risk Committee, which are now integrated into the Group's internal audit programme for review.

The most relevant near-term and emerging risks, along with the Group's assessment of their potential impact on the business and associated required mitigations, have been recognised as follows:

Risk

COVID-19

As a responsible operator, EnQuest continues to monitor the evolving situation and consequent risks with regard to the COVID-19 pandemic, recognising it could impact a number of the Group's principal risks, such as human resources and oil price, which are disclosed later in the key business risks section of this report.

At the time of publication of EnQuest's full-year results, the Group's day-to-day operations continue without being materially affected.

Appetite

The Group's risk appetite for COVID-19 is reported against the Group's impacted principal risks.

Mitigation

The Group continues to work 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 and level of risk.

The biggest risk related to COVID-19 is the impact on oil prices if movement restrictions impact the demand for oil. See 'Oil and gas price' risk on page 19 for more information on how the Group mitigates against price risk.

Risk

Climate change

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

Appetite

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

The Group's risk appetite for climate change risk is reported against the Group's impacted principal risks.

Mitigation

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

The Group endeavours to reduce emissions through improving operational performance, minimising flaring and venting where possible, and applying appropriate and economic improvement initiatives, noting the ability to reduce carbon emissions will be constrained by the original design of later-life assets.

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

The Group has committed to a 10% reduction in Scope 1 and 2 emissions over three years, from a year-end 2020 baseline, with the achievement linked to reward. Progress is reported to the Safety, Climate and Risk Committee of the Board in relation to progress of emission reductions, identification of economically viable emissions savings opportunities across the Group's portfolio of assets, aligned to the emissions management strategy.

During 2021, the Group established an Infrastructure and New Energy business that is responsible for delivering the Group's emission reduction objectives in line with Group and industry targets and advancing new energy and decarbonisation opportunities.

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

Risk

Evolving geopolitical situation

Having assessed its commercial and IT security arrangements, the Group does not consider it has a material adverse exposure to the geopolitical situation with respect to the sanctions imposed on Russia, although recognises the evolving situation is causing oil price volatility. The Group will continue to monitor its position to ensure it remains compliant with any sanctions in place.

Key business risks

The Group's principal risks (identified from the 'Risk Library') are those which could prevent the business from executing its strategy and creating value for shareholders or lead to a significant loss of reputation. The Board has carried out a robust assessment of the principal risks facing the Group, including those that would threaten its business model, future performance, solvency or liquidity.

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

Set out on the following pages are:

∙	the principal risks and mitigations;
∙	an estimate of the potential impact and likelihood of occurrence after the mitigation actions, along with how these have changed in the past year; and
∙	an articulation of the Group's risk appetite for each of these principal risks.

Amongst these, the key risks the Group currently faces are materially lower oil prices for an extended period (see 'Oil and gas prices' risk on page 19), which may impact our ability to refinance debt and/or execute growth opportunities, and/or a materially lower than expected production performance for a prolonged period (see 'Production' risk on page 19 and 'Subsurface risk and reserves replacement' on page 22).

Risk

Health, Safety and Environment ('HSE')

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

Potential impact

Medium (2020 Medium)

Likelihood

Medium (2020 Medium)

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

There remains a risk to the availability of competent people given the potential impacts of COVID-19.

Appetite

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

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

In 2021, EnQuest achieved a top quartile Lost Time Incident frequency rate and hydrocarbon release frequency rate in the UK.

Mitigation

The Group maintains, in conjunction with its core contractors, a comprehensive programme of assurance activities and has undertaken a series of deep dives into the Risk Bowties that have demonstrated the robustness of the management process and identified opportunities for improvement. A Group-aligned HSE continuous improvement programme is in place, promoting a culture of engagement and transparency in relation to HSE matters. HSE performance is discussed at each Board meeting and the mitigation of HSE risk continues to be a core responsibility of the Safety, Climate and Risk Committee. During 2021, the Group continued to focus on the control of major accident hazards and 'SAFE Behaviours'.

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

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

In 2021, an independent asset integrity review was undertaken across the Group. This allowed for a deep review of asset integrity looking at people, plant and process aspects in relation to the management of risk. The outcome was a more transparent and robust approach to cost allocation to key risk threats that could impact asset integrity.

The Group continues to monitor the evolving situation with regard to the impacts of COVID-19 in conjunction with a variety of stakeholders, including industry and medical organisations. Appropriate actions will continue to be implemented in accordance with expert advice and the level of risk.

Risk

Oil and gas prices

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

Potential impact

High (2020 High)

Likelihood

High (2020 High)

The potential impact and likelihood remain high, reflecting the uncertain economic outlook, including possible impacts from COVID-19, and the potential acceleration of 'peak oil' demand.

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

Appetite

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

Mitigation

This risk is being mitigated by a number of measures.

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

The Group monitors oil price sensitivity relative to its capital commitments. The terms of the Group's reserve based lending facility also requires hedging of its production (see page 60). The Group has a policy which allows hedging of its production (see page 60). As at 23 March 2022, the Group had hedged approximately 12.1 MMbbls for 2022 and 2023. This ensures that the Group will receive a minimum oil price for some of its production.

In order to develop its resources, the Group needs to be able to fund the required investment. The Group will therefore regularly review and implement suitable policies to hedge against the possible negative impact of changes in oil prices.

The Group has an established in-house trading and marketing function to enable it to enhance its ability to mitigate the exposure to volatility in oil prices.

Further, as described previously, the Group's focus on production efficiency supports mitigation of a low oil price environment.

Risk

Production

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

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

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

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

Potential impact

High (2020 High)

Likelihood

Medium (2020 Medium)

There has been no material change in the potential impact or likelihood. Operational issues at Magnus, which resulted in the Group lowering its production guidance for 2021, have been offset by the Group acquiring a non-operated interest in the Golden Eagle area in the UK North Sea.

Appetite

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

Mitigation

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

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

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

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

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

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

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

Risk

Financial

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

Significant reductions in the oil price or material reductions in production will likely have a material impact on the Group's ability to repay or refinance its existing credit facilities. Prolonged low oil prices, cost increases, including those related to an environmental incident, and production delays or outages, could threaten the Group's liquidity and/or ability to comply with relevant covenants. Similar conditions could impact the Group's ability to refinance the bonds ahead of maturity in October 2023. Further information is contained in the Financial review, particularly within the going concern and viability disclosures on pages 14 to 16.

Potential impact

High (2020 High)

Likelihood

High (2020 High)

There is no change to the potential impact or likelihood, reflecting the continued economic uncertainty and potential impact of oil price fluctuations.

The Group successfully refinanced its existing term loan and revolving credit facility during 2021 and completed the Golden Eagle area acquisition.

There is potential for the availability and cost of capital to increase and insurance availability to erode, as factors such as climate change and other ESG concerns and oil price volatility may reduce investors' and insurers' acceptable levels of oil and gas sector exposure, and the cost of emissions trading certificates may continue to trend higher along with insurers' reluctance to provide surety bonds for decommissioning, thereby requiring the Group to fund decommissioning security through its balance sheet.

Appetite

The Group recognises that significant leverage was required to fund its growth as low oil prices impacted revenues. However, it is intent on further reducing its leverage levels, maintaining liquidity, controlling costs and complying with its obligations to finance providers while delivering shareholder value, recognising that reasonable assumptions relating to external risks need to be made in transacting with finance providers.

Mitigation

Debt reduction is a strategic priority. During 2021, the Group refinanced its secured credit facility, enabling the acquisition of the Golden Eagle area. Strong cash generation enabled the Group to finance a larger portion of the Golden Eagle acquisition from cash flow, resulting in a lower than expected drawdown on the Group's RBL facility. At 23 March 2022, the RBL facility was drawn to $330 million, with voluntary early repayments ensuring the Group remains ahead of the facility amortisation schedule.

Ongoing compliance with the financial covenants under the Group's reserve based lending facility is actively monitored and reviewed.

EnQuest generates operating cash inflow from the Group's producing assets. The Group reviews its cash flow requirements on an ongoing basis to ensure it has adequate resources for its needs.

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

The Group continues to explore options to refinance its retail and high yield bonds ahead of maturity in October 2023.

These steps, together with other mitigating actions available to management, are expected to provide the Group with sufficient liquidity to strengthen its balance sheet further.

Risk

Competition

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

Potential impact

High (2020 High)

Likelihood

High (2020 High)

The potential impact and likelihood remain unchanged, with a number of competitors assessing the acquisition of available oil and gas assets and the rising potential for consolidation (e.g. through reverse mergers).

Appetite

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

Mitigation

The Group has strong technical, commercial and business development capabilities to ensure that it is well positioned to identify and execute potential acquisition opportunities, utilising innovative structures as may be appropriate.

The Group maintains good relations with oil and gas service providers and constantly keeps the market under review. EnQuest has a dedicated marketing and trading group of experienced professionals responsible for maintaining relationships across relevant energy markets, thereby ensuring the Group achieves the highest possible value for its production.

In addition, the marketing and trading group is responsible for the Group's commodity price risk management activities in accordance with the Group's business strategy.

Risk

IT security and resilience

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

Potential impact

Medium (2020 Medium)

Likelihood

Medium (2020 Medium)

There has been no change to the potential impact or likelihood, with the Group enhancing its IT security in light of the evolving geopolitical situation.

Appetite

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

Mitigation

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

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

The Safety, Climate and Risk Committee undertook additional analyses of cyber‑security risks in 2021. The Group has a dedicated cyber‑security manager and work on assessing the cyber-security environment and implementing improvements as necessary will continue during 2022.

Risk

Portfolio concentration

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

Potential impact

High (2020 High)

Likelihood

High (2020 High)

The Group is currently focused on oil production and does not have significant exposure to gas or other sources of income.

The decisions taken to accelerate cessation of production at a number of the Group's assets has further reduced the number of producing assets and so increased portfolio concentration.

During 2021, the Group acquired a 26.69% non-operated equity interest in the Golden Eagle area, a 40.81% operating interest in the Bressay heavy-oil field and 100.00% equity interest in the P1078 licence in the UK North Sea containing the proven Bentley heavy-oil discovery.

The Group continues to assess acquisition growth opportunities with a view to improving its asset diversity over time.

The Group also established an Infrastructure and New Energy business to unlock renewable energy and decarbonisation opportunities in the medium to long term.

Appetite

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

Mitigation

This risk is mitigated in part through acquisitions. For all acquisitions, the Group uses a number of business development resources, both in the UK and internationally, to liaise with vendors/governments and evaluate and transact acquisitions. This includes performing extensive due diligence (using in-house and external personnel) and actively involving executive management in reviewing commercial, technical and other business risks together with mitigation measures.

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

Risk

Subsurface risk and reserves replacement

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

Potential impact

High (2020 High)

Likelihood

Medium (2020 Medium)

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

Low oil prices or prolonged field shutdowns requiring high-cost remediation which accelerate cessation of production can potentially affect development of contingent and prospective resources and/or reserves certifications.

Appetite

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

Mitigation

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

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

The Group has material reserves and resources at Magnus, Kraken, Golden Eagle and PM8/Seligi that it believes can primarily be accessed through low-cost subsea drilling and tie-backs to existing infrastructure. EnQuest continues to evaluate the substantial 2C resources at Bressay, Bentley and PM409 to identify future drilling prospects. Bressay and Bentley are located close to the Group's Kraken development, while PM409 is contiguous to the Group's existing PM8/Seligi PSC, providing low-cost tie-back opportunities.

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

Risk

Project execution and delivery

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

Potential impact

Medium (2020 Medium)

Likelihood

Low (2020 Low)

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

Appetite

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

Mitigation

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

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

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

Risk

Fiscal risk and government take

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

Potential impact

High (2020 High)

Likelihood

Medium (2020 Medium)

There has been no material change in the potential impact or likelihood, although the exit of the UK from the European Union has impacted the regulatory environment going forward, for example by affecting the cost of emissions trading certificates through the smaller UK emissions trading scheme.

Appetite

The Group faces an uncertain macroeconomic and regulatory environment.

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

Mitigation

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

All business development or investment activities recognise potential tax implications and the Group maintains relevant internal tax expertise.

At an operational level, the Group has procedures to identify impending changes in relevant regulations to ensure legislative compliance.

Risk

International business

While the majority of the Group's activities and assets are in the UK, the international business is still material. The Group's international business is subject to the same risks as the UK business (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.

Potential impact

Medium (2020 Medium)

Likelihood

Medium (2020 Medium)

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

Appetite

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

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

Mitigation

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

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

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

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

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

Risk

Joint venture partners

Failure by joint venture parties to fund their obligations.

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

Potential impact

Medium (2020 Medium)

Likelihood

Low (2020 Low)

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

Appetite

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

Mitigation

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

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

Risk

Reputation

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

Potential impact

High (2020 High)

Likelihood

Low (2020 Low)

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

Appetite

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

Mitigation

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

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

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

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

All personnel are authorised to shut down production for safety-related reasons. As an example, the Group acted promptly in temporarily shutting down the Magnus platform when it was clear its flaring consent would be breached.

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

Risk

Human resources

The Group's success continues to be dependent upon its ability to attract and retain key personnel and develop organisational capability to deliver strategic growth. Industrial action across the sector, or the availability of competent people given the potential impacts of COVID-19, could also impact the operations of the Group.

Potential impact

Medium (2020 Medium)

Likelihood

Medium (2020 Medium)

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

Appetite

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

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

Mitigation

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

The Group recognises that its people are critical to its success and so is continually evolving EnQuest's end‑to‑end people management processes, including recruitment and selection, career development and performance management. This ensures that EnQuest has the right person for the job and that appropriate training, support and development opportunities are provided, with feedback collated to drive continuous improvement whilst delivering SAFE Results. The culture of the Group is an area of ongoing focus and employee surveys and forums have been undertaken to understand employees' views on key areas, including diversity and inclusion, in order to develop appropriate action plans.

EnQuest is considering the appropriate balance for its onshore teams between site, office and home working to promote strong productivity and business performance facilitated by an engaged workforce. The Group also maintains market‑competitive contracts with key suppliers to support the execution of work where the necessary skills do not exist within the Group's employee base.

The Group recognises that there is a gender pay gap within the organisation but that there is no issue with equal pay for the same tasks. EnQuest also recognises that fewer young people may join the industry due to climate change-related factors. EnQuest aims to attract the best talent, recognising the value and importance of diversity.

To ensure improved diversity in the Group's leadership, various targets have been implemented during 2021.

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

Following its introduction in 2019, the Group's global employee forum has continued to add to EnQuest's employee communication and engagement strategy, improving interaction between the workforce and the Board.

KEY PERFORMANCE INDICATORS

	2021	2020	2019
ESG metrics:
Group LTIF¹	0.21	0.22	0.57
Emissions (kilo-tonnes of CO₂ equivalent)	1,145.3	1,342.8	1,511.6
Business performance data:
Production (Boepd)	44,415	59,116	68,606
Unit opex (production and transportation costs) ($/Boe)²	20.5	15.2	20.6
Cash expenditures ($ million)	117.6	173.0	248.6
Capital²	51.8	131.4	237.5
Abandonment	65.8	41.6	11.1
Reported data:
Cash generated from operations ($ million)	756.9	567.2	993.4
Net debt including PIK ($ million)²	1,222.0	1,279.7	1,413.0
Net 2P reserves (MMboe)	194	189	213

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

² See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 66

OIL AND GAS RESERVES AND RESOURCES

EnQuest oil and gas reserves and resources

	UKCS¹²		Other regions¹²		Total¹²
	MMboe	MMboe	MMboe	MMboe	MMboe
Proven and probable reserves^{1, 2, 3 and 4}
At 31 December 2020		166		22	189
Acquisitions and dispoals⁵	19		-		19
Revisions of previous estimates	-		(1)		(1)
Transfers from contingent resources⁶	3		1		4
		22		(0)	22
Production:
Export meter	(14)		(2)		(16)
Volume adjustments⁷	0		-
		(14)		(2)	(16)
Total proven and probable reserves at 31 December 2021⁸		174		20	194
Contingent resources^{1, 2 and 9}
At 31 December 2020		77		87	164
Acquisitions and dispoals¹⁰		249		-	249
Revisions of previous estimates		(6)		(1)	(7)
Promoted to reserves¹¹		(3)		(1)	(4)
Total contingent resources at 31 December 2021		316		86	402

Notes:

1 Reserves are quoted on a net entitlement basis, resources are quoted on a working interest basis

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

3 The Group's proven and probable reserves have been audited by a recognised Competent Person in accordance with the definitions set out under the 2018 Petroleum Resources Management System and supporting guidelines issued by the Society of Petroleum Engineers

4 All UKCS volumes are presented pre-SVT value adjustment

5 Acquisition of 26.69% non-operated interest in Golden Eagle

6 Transfers from 2C resources at Kraken, Magnus and PM8/Seligi

7 Correction of export to sales volumes

8 The above proven and probable reserves include volumes that will be consumed as fuel gas; including c.7 MMboe at Magnus, c.1 MMboe at Kraken and c.1 MMboe at Golden Eagle

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

10 Acquisition of 40.81% interest in Bressay, 100.00% interest in Bentley and 26.69% non-operated interest in Golden Eagle

11 Kraken, Magnus and PM8/Seligi opportunity maturation

12 Rounding may apply

Group Income Statement

For the year ended 31 December 2021

		2021			2020 restated⁽ⁱ⁾
	Notes	Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in year $'000	Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in year $'000
Revenue and other operating income	5(a)	1,320,265	(54,451)	1,265,814	855,074	8,778	863,852
Cost of sales	5(b)	(900,433)	(7,201)	(907,634)	(785,455)	(13,626)	(799,081)
Gross profit/(loss)		419,832	(61,652)	358,180	69,619	(4,848)	64,771
Net impairment reversal/(charge) to oil and gas assets	4	-	39,715	39,715	-	(422,495)	(422,495)
General and administration expenses	5(c)	(363)	-	(363)	(6,105)	-	(6,105)
Other income	5(d)	30,990	162,647	193,637	18,100	138,249	156,349
Other expenses	5(e)	(7,278)	(3,832)	(11,110)	(101,633)	(956)	(102,589)
Profit/(loss) from operations before tax and finance income/(costs)		443,181	136,878	580,059	(20,019)	(290,050)	(310,069)
Finance costs	6	(169,451)	(58,395)	(227,846)	(179,818)	(77,259)	(257,077)
Finance income	6	228	-	228	1,171	-	1,171
Profit/(loss) before tax		273,958	78,483	352,441	(198,666)	(367,309)	(565,975)
Income tax	7	(53,674)	78,221	24,547	172,479	(76,449)	96,030
Profit/(loss) for the year attributable to owners of the parent		220,284	156,704	376,988	(26,187)	(443,758)	(469,945)
Total comprehensive profit/(loss) for the year, attributable to owners of the parent				376,988			(469,945)

(i) The comparative information has been restated as a result of change in accounting policy and prior period error. For more information, 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	8	$	$	$	$
Basic		0.127	0.217	(0.016)	(0.290)
Diluted		0.125	0.214	(0.016)	(0.290)

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

Group Balance Sheet

At 31 December 2021

	Notes	2021 $'000	2020 restated⁽ⁱ⁾ $'000
ASSETS
Non-current assets
Property, plant and equipment	10	2,821,998	2,633,917
Goodwill	11	134,400	134,400
Intangible assets	12	47,667	27,546
Deferred tax assets	7(c)	702,970	659,803
Other financial assets	19	6	7
		3,707,041	3,455,673
Current assets
Inventories	13	73,023	59,784
Trade and other receivables	16	296,068	118,715
Current tax receivable		2,368	5,601
Cash and cash equivalents	14	286,661	222,830
Other financial assets	19	472	-
		658,592	406,930
TOTAL ASSETS		4,365,633	3,862,603
EQUITY AND LIABILITIES
Equity
Share capital and premium	20	392,196	345,420
Share-based payment reserve		6,791	1,016
Retained earnings	20	121,769	(255,219)
TOTAL EQUITY		520,756	91,217
Non-current liabilities
Borrowings	18	191,109	37,854
Bonds	18	1,081,596	1,045,041
Leases liabilities	24	442,500	548,407
Contingent consideration	22	380,301	448,384
Provisions	23	754,266	741,453
Deferred tax liabilities	7(c)	3,418	6,385
		2,853,190	2,827,524
Current liabilities
Borrowings	18	210,505	414,430
Leases liabilities	24	128,281	99,439
Contingent consideration	22	30,477	73,877
Provisions	23	140,676	98,954
Trade and other payables	17	420,544	255,155
Other financial liabilities	19	55,247	2,007
Current tax payable		5,957	-
		991,687	943,862
TOTAL LIABILITIES		3,844,877	3,771,386
TOTAL EQUITY AND LIABILITIES		4,365,633	3,862,603

(i) The comparative information has been restated as a result of change in accounting policy and prior period error. For more information, see note 2 Basis of preparation - Restatements

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

The financial statements were approved by the Board of Directors and authorised for issue on 23 March 2022 and signed on its behalf by:

Jonathan Swinney

Chief Financial Officer

Group Statement of Changes in Equity

For the year ended 31 December 2021

	Share capital and share premium $'000	Merger Reserve⁽ⁱ⁾ $'000	Share-based payments reserve $'000	Retained earnings $'000	Total $'000
Balance at 1 January 2020	345,420	662,855	(1,085)	(448,129)	559,061
Profit/(loss) for the year (restated)⁽ⁱⁱ⁾	-	-	-	(469,945)	(469,945)
Total comprehensive loss for the year (restated)⁽ⁱⁱ⁾	-	-	-	(469,945)	(469,945)
Share-based payment (see note 21)	-	-	3,401	-	3,401
Shares purchased on behalf of Employee Benefit Trust	-	-	(1,300)	-	(1,300)
Write down of oil and gas assets	-	(662,855)	-	662,855	-
Balance at 31 December 2020 (restated)⁽ⁱⁱ⁾	345,420	-	1,016	(255,219)	91,217
Profit/(loss) for the year	-	-	-	376,988	376,988
Total comprehensive profit for the year	-	-	-	376,988	376,988
Issue of share capital, net of expenses	46,200	-	-	-	46,200
Share-based payment (see note 21)	-	-	6,351	-	6,351
Shares purchased on behalf of Employee Benefit Trust	576	-	(576)	-	-
Balance at 31 December 2021	392,196	-	6,791	121,769	520,756

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

(ii) The comparative information has been restated as a result of change in accounting policy and prior period error. For more information, see note 2 Basis of preparation - Restatements

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

Group Statement of Cash Flows

For the year ended 31 December 2021

	Notes	2021 $'000	2020 restated⁽ⁱ⁾ $'000
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations	29	756,928	567,165
Cash received from insurance		674	-
Cash received/(paid) on sale/(purchase) of financial instruments		(277)	6,226
Decommissioning spend		(65,791)	(41,605)
Income taxes paid		(17,396)	(10,366)
Net cash flows from/(used in) operating activities		674,138	521,420
INVESTING ACTIVITIES
Purchase of property, plant and equipment		(43,712)	(131,376)
Purchase of intangible oil and gas assets		(8,127)	-
Purchase of other intangible assets	12	(10,052)	-
Net cash received on termination of Tanjong Baram risk service contract		-	51,054
Repayment of Magnus contingent consideration - Profit share	22	(968)	(41,071)
Acquisitions		(258,627)	-
Interest received		256	796
Net cash flows (used in)/from investing activities		(321,230)	(120,597)
FINANCING ACTIVITIES
Net proceeds of share issue		47,782	-
Proceeds of loans and borrowings		125,000	-
Repayment of loans and borrowings		(184,276)	(210,671)
Repayment of Magnus contingent consideration - Vendor loan	22	(73,728)	(20,702)
Shares purchased by Employee Benefit Trust		(576)	(1,153)
Repayment of obligations under financing leases	24	(136,651)	(123,001)
Interest paid		(63,025)	(42,961)
Other finance costs paid		-	(2,526)
Net cash flows from/(used in) financing activities		(285,474)	(401,014)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS		67,434	(191)
Net foreign exchange on cash and cash equivalents		(3,603)	2,566
Cash and cash equivalents at 1 January		222,830	220,455
CASH AND CASH EQUIVALENTS AT 31 DECEMBER		286,661	222,830
Reconciliation of cash and cash equivalents
Total cash at bank and in hand	14	276,970	221,155
Restricted cash	14	9,691	1,675
Cash and cash equivalents per balance sheet		286,661	222,830

(i) The comparative information has been restated as a result of change in accounting policy and prior period error. For more information, see note 2 Basis of preparation - Restatements

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

Notes to the Group Financial Statements

For the year ended 31 December 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 address of the Company's registered office is 5^th Floor, Cunard House, 15 Regent Street, London, SW1Y 4LR.

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

The Group's financial statements for the year ended 31 December 2021 were authorised for issue in accordance with a resolution of the Board of Directors on 23 March 2022.

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

2. Basis of preparation

The consolidated financial statements have been prepared in accordance with UK-adopted International Accounting Standards and International Financial Reporting Standards as issued by the IASB and in conformity with the requirements of the Companies Act 2006. The accounting policies which follow set out those policies which apply in preparing the financial statements for the year ended 31 December 2021.

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

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

Restatements

Presentation of rental income

EnQuest receives rental income for sub-leasing space in its corporate offices. The Group previously presented the rental income associated with office sub-leases 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 $1.8 million reduction in revenue and other operating income and a $1.8 million 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 its interim report, the Group 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 $155.9 million with respect to 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 these Group financial statements.

Group Income Statement⁽ⁱ⁾

	2020 (as previously reported)				Restatement adjustment		2020 restated
	Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in period $'000	$'000		Business performance $'000		Remeasurements and exceptional items (note 4) $'000	Reported in period $'000
Profit/(loss) before tax	(198,666)	(367,309)	(565,975)			(198,666)		(367,309)	(565,975)
Income tax	172,479	(232,306)	(59,827)	155,857		172,479		(76,449)	96,030
Profit/(loss) for the year attributable to owners of the parent	(26,187)	(599,615)	(625,802)	155,857		(26,187)		(443,758)	(469,945)
Total comprehensive profit/(loss) for the period, attributable to owners of the parent			(625,802)	155,857					(469,945)

Earnings per share	$	$		$	$
Basic	(0.016)	(0.378)	0.088	(0.016)	(0.290)
Diluted	(0.016)	(0.378)	0.088	(0.016)	(0.290)

(i) Only the impact of the material deferred tax asset restatement presented

Group Balance Sheet⁽ⁱ⁾

	2020 (as previously reported) $'000	Restatement adjustment $'000	2020 restated $'000
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

(i) Only the impact of the material deferred tax asset restatement presented

Going concern

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

At 31 December 2021, $415.0 million was drawn on the RBL, with early voluntary repayments of $85.0 million made in the first quarter of 2022.

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 $67.5/bbl for 2022 and $63.0/bbl for 2023;

· Production risking of c.5% for 2022 and 2023; and

· 2.5% increase in operating costs.

New standards and interpretations

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

· Interest Rate Benchmark Reform - Phase 2 (Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16)

· COVID-19-Related Rent Concessions beyond 30 June 2021 (Amendment to IFRS 16)

Standards issued but not yet effective

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

IFRS 17	Insurance Contracts
IFRS 10 and IAS 28 (amendments)	Sale or Contribution of Assets between an Investor and its Associate or Joint Venture
Amendments to IAS 1 Amendments to IAS 8	Classification of Liabilities as Current or Non-current and Disclosure of Accounting Policies Disclosure of Accounting Policies
Amendments to IFRS 3 Amendments to IAS 12	Reference to the Conceptual Framework Deferred Tax related to Assets and Liabilities arising from a Single Transaction
Amendments to IAS 16	Property, Plant and Equipment - Proceeds before Intended Use
Amendments to IAS 37	Onerous Contracts - Cost of Fulfilling a Contract
Annual Improvements to IFRS Standards 2018-2020 Cycle	Amendments to IFRS 1 First-time Adoption of International Financial Reporting Standards, IFRS 9 Financial Instruments, IFRS 16 Leases, and IAS 41 Agriculture

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

Basis of consolidation

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

· has power over the investee;

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

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

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

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

Joint arrangements

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

Most of the Group's activities are conducted through joint operations, whereby the parties that have joint control of the arrangement have the rights to the assets, and obligations for the liabilities relating to the arrangement. The Group recognises its share of assets, liabilities, income and expenses of the joint operation in the consolidated financial statements on a line-by-line basis. During 2021, the Group did not have any material interests in joint ventures or in associates as defined in IAS 28.

Foreign currencies

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

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

Emissions liabilities

The Group operates in an energy intensive industry and is therefore required to partake in emission trading schemes ('ETS') (2021: UK ETS, 2020: EU ETS). The Group recognises an emission liability in line with the production of emissions that give rise to the obligation. To the extent the liability is covered by allowances held, the liability is recognised at the cost of these allowances held and if insufficient allowances are held, the remaining uncovered portion is measured at the spot market price of allowances at the balance sheet date. The expense is presented within 'production costs' under 'cost of sales' and the accrual is presented in 'trade and other payables'. Any allowance purchased to settle the Group's liability is recognised on the balance sheet as an intangible asset. Both the emission allowances and the emission liability are derecognised upon settling the liability with the respective regulator.

Use of judgements, estimates and assumptions

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

The accounting judgements and estimates that have a significant impact on the results of the Group are set out below and should be read in conjunction with the information provided in the Notes to the financial statements. Judgements and estimates, not all of which are significant, made in assessing the impact of climate change and the transition to a lower carbon economy on the consolidated financial statements are also set out below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year, this is specifically noted.

Climate change and energy transition

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

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

While the pace of transition to a lower carbon economy is uncertain, oil and natural gas demand is expected to remain a key element of the energy mix for many years based on stated policies, commitments and announced pledges to reduce emissions. Therefore, given the useful lives of the Group's current portfolio of oil and gas assets, a material adverse change is not expected to the carrying values of EnQuest's assets and liabilities as a result of climate change and the transition to a lower carbon economy.

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

Critical accounting judgements and key sources of estimation uncertainty

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

Recoverability of asset carrying values

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

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

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

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

The estimates for assumptions made in impairment tests in 2021 relating to discount rates and oil prices are discussed below. Changes in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the Group's assets within the next financial year.

Discount rates

For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Fair value less costs of disposal discounted cash flow calculations use the post-tax discount rate. The discount rate is derived using the weighted average cost of capital methodology. The discount rates applied in impairment tests are reassessed each year and, in 2021, the post-tax discount rate was 10% (2020: 10%).

Oil prices

The price assumptions used for FVLCD impairment testing were based on latest internal forecasts as at 31 December 2021, which assume short-term market prices will revert to the Group's assessment of long-term price. These price forecasts reflect EnQuest's long-term views of global supply and demand, including the potential financial impacts on the Group of climate change and the transition to a low carbon economy as outlined in the Basis of Preparation, and are benchmarked with external sources of information such as analyst forecasts. The Group's price forecasts are reviewed and approved by management and challenged by the Audit Committee.

EnQuest revised its oil price assumptions for FVLCD impairment testing compared to those used in 2020. The assumptions up to 2024 were increased to reflect an improved demand outlook as at the end of 2021. Oil prices rose 51% in 2021 from 2020 due to a strong rebound in oil demand as the impact of COVID-19 eased and there were measured increases in OPEC+ supply combined with continued capital discipline across the industry impacting supply. A summary of the Group's revised price assumptions is provided below. These assumptions, which represent management's best estimate of future prices, sit within the range of external forecasts and are considered by EnQuest to be broadly in line with a range of transition paths consistent with the Paris climate goals. However, they do not correspond to any specific Paris-consistent scenario. An inflation rate of 2% (2020: 2%) is applied from 2025 onwards to determine the price assumptions in nominal terms. Discounts or premiums are applied to price assumptions based on the characteristics of the oil produced and of the terms of the relevant sales contracts.

	2022	2023	2024	2025>
Brent oil ($/bbl)	75.0	70.0	70.0	60.0

The increase in oil prices in the first quarter of 2022 relating to the Russia-Ukraine conflict is a result of conditions that arose after the balance sheet date. As such, the Group's future oil price assumptions used in impairment tests to assess the recoverable amount of assets at the balance sheet date have not been adjusted.

A net impairment reversal was recognised in 2021. See note 10 for further information.

The price assumptions used in 2020 were $47.0/bbl (2021), $55.0/bbl (2022), $60.0/bbl (2023) and $60.0/bbl real thereafter, inflated at 2.0% per annum from 2024.

Oil and natural gas reserves

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

The Group uses proven and probable ('2P') reserves (see page 27) as the basis for calculations of expected future cash flows from underlying assets because this represents the reserves management intends to develop and it is probable that a market participant would attribute value to them. Third-party audits of EnQuest's reserves and resources are conducted annually.

Sensitivity analyses

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

Price reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of EnQuest's oil and gas properties by approximately $283.5 million, which is approximately 10% of the net book value of property, plant and equipment as at 31 December 2021.

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

Management also tested the impact of a one percentage point change in the discount rate used for FVLCD impairment testing of oil and gas properties. If the discount rate was one percentage point higher across all tests performed, the net impairment reversal recognised in 2021 would have been approximately $35.1 million lower. If the discount rate was one percentage point lower, the net impairment reversal recognised would have been approximately $38.3 million higher.

Goodwill

Irrespective of whether there is any indication of impairment, EnQuest is required to test annually for impairment of goodwill acquired in business combinations. The Group carries goodwill of approximately $134.4 million on its balance sheet (2020: $134.4 million), principally relating to the Magnus oil field transactions. Sensitivities and additional information relating to impairment testing of goodwill are provided in note 11.

Deferred tax

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

75% Magnus acquisition contingent consideration

Sensitivities and additional information relating to the 75% Magnus acquisition contingent consideration are provided in note 22.

Provisions

Estimates: Decommissioning costs will be incurred by the Group at the end of the operating life of some of the Group's oil and gas production facilities and pipelines. The Group assesses its decommissioning provision at each reporting date. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, estimates of the extent and costs of decommissioning activities, the emergence of new restoration techniques and experience at other production sites. The expected timing, extent and amount of expenditure may also change; for example, in response to changes in oil and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results.

The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed half-yearly. The nominal interest rate used to determine the balance sheet obligations at the end of 2021 was 2% (2020: 2%). The weighted average period over which decommissioning costs are generally expected to be incurred is estimated to be approximately ten years. Costs at future prices are determined by applying an inflation rate of 2% (2020: 2%) to decommissioning costs.

Further information about the Group's provisions is provided in note 23. Changes in assumptions in relation to the Group's provisions could result in a material change in their carrying amounts within the next financial year. A 0.5 percentage point decrease in the nominal discount rate applied could increase the Group's provision balances by approximately $40.9 million (2020: $38.4 million). The pre-tax impact on the Group income statement would be a charge of approximately $5.9 million.

Intangible oil and gas assets

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

3. Segment information

The Group's organisational structure reflects the various activities in which EnQuest is engaged. Management has considered the requirements of IFRS 8 Operating Segments in regard to the determination of operating segments and concluded that at 31 December 2021, the Group had two significant operating segments: the North Sea and Malaysia. Operations are managed by location and all information is presented per geographical segment. The Group's segmental reporting structure remained in place throughout 2021. The North Sea's activities include Upstream operations, Decommissioning and Infrastructure & New Energy. Malaysia's activities include Upstream operations. The Group's reportable segments may change in the future depending on the way that resources may be allocated and performance assessed by the Chief Operating Decision Maker, who for EnQuest is the Chief Executive. The information reported to the Chief Operating Decision Maker does not include an analysis of assets and liabilities, and accordingly this information is not presented.

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

Restated Year ended 31 December 2020^(iv) $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(i)	Consolidated
Revenue:
Revenue from contracts with customers	792,508	62,917	-	855,425	-	855,425
Other operating income	5,428	-	280	5,708	2,719	8,427
Total revenue and other operating income	797,936	62,917	280	862,929	2,719	863,852
Income/(expenses) line items:
Depreciation and depletion	(430,169)	(15,638)	(56)	(445,863)	-	(445,863)
Net impairment (charge)/reversal to oil and gas assets	(422,495)	-	-	(422,495)	-	(422,495)
Segment profit/(loss)(ii)	(318,952)	4,153	3,372	(311,427)	1,358	(310,069)
Other disclosures:
Capital expenditure(iii)	81,504	2,144	-	83,648	-	83,648

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

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

(iii) Capital expenditure consists of property, plant and equipment and intangible exploration and appraisal assets

(iv) 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

Reconciliation of profit/(loss):

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000
Segment profit/(loss)	688,635	(311,427)
Finance costs	(227,846)	(257,077)
Finance income	228	1,171
Gain/(loss) on oil and foreign exchange derivatives⁽ⁱ⁾	(108,576)	1,358
Profit/(loss) before tax	352,441	(565,975)

(i) Includes $54.6 million realised losses on derivatives and $54.0 million unrealised losses on derivatives

Revenue from two customers relating to the North Sea operating segment each exceeds 10% of the Group's consolidated revenue arising from sales of crude oil, with amounts of $241.7 million and $150.6 million per each single customer (2020: four customers; $188.9 million, $143.4 million, $113.1 million and $84.9 million per each single customer).

4. Remeasurements and exceptional items

Accounting policy

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

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

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

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

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

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

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

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

Restated Year ended 31 December 2020 $'000	Fair value remeasurement(i)	Impairments and write-offs(ii)	Other(iii)	Total
Revenue and other operating income	8,778	-	-	8,778
Cost of sales	(1,932)	-	(11,694)	(13,626)
Net impairment (charge)/reversal on oil and gas assets	-	(422,495)	-	(422,495)
Other income	138,249	-	-	138,249
Other expenses	-	-	(956)	(956)
Finance costs	-	-	(77,259)	(77,259)
	145,095	(422,495)	(89,909)	(367,309)
Tax on items above	(57,687)	163,267	33,175	138,755
Derecognition of undiscounted deferred tax asset (restated)^(iv)	-	(215,204)	-	(215,204)
	87,408	(474,432)	(56,734)	(443,758)

(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 $(54.0) million. Other income relates to the fair value remeasurement of contingent consideration relating to the acquisition of Magnus and associated infrastructure of $140.1 million (note 22) (2020: $138.2 million)

(ii) Impairments and write offs include a net impairment reversal of tangible oil and gas assets and right-of-use assets totalling $39.7 million (note 10) (2020: impairment of $422.5 million)

(iii) Other items are made up of the following: Cost of sales includes $7.7 million mainly related to a provision for a dispute with a third party contractor. In 2020, cost of sales included $11.7 million for the provision on the PM8/Seligi riser repair and redundancy costs in relation to the Group's transformation programme. Other income in 2021 of $22.6 million (2020: nil) includes the finalisation of previous asset acquisitions, $12.0 million, and the recognition of insurance income, $9.0 million, related to the PM8/Seligi riser incident, Other expense $3.8 million relates to expenses incurred on the repayment of the BP vendor loan and Finance costs relates to Magnus contingent consideration of $58.3 million (note 22) (2020: $77.3 million). These are largely non-cash items.

(iv) Non-cash deferred tax recognition (2020 restated see note 2 Basis of preparation - Restatements) following the Group's acquisition of Golden Eagle and the Group's higher oil price assumptions

5. Revenue and expenses

(a) Revenue and other operating income

Accounting policy

Revenue from contracts with customers

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

Sale of crude oil, gas and condensate

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

Tariff revenue for the use of Group infrastructure

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

Other operating income

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

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

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 restated $'000
Revenue from contracts with customers:
Revenue from crude oil sales	1,139,171	779,865
Revenue from gas and condensate sales(i)	244,073	60,486
Tariff revenue	654	15,074
Total revenue from contracts with customers	1,383,898	855,425
Rental income from vessels⁽ⁱⁱ⁾	702	3,910
Realised (losses)/gains on oil derivative contracts (see note 19)	(67,679)	(6,059)
Other	3,344	1,798
Business performance revenue and other operating income	1,320,265	855,074
Unrealised (losses)/gains on oil derivative contracts(iii) (see note 19)	(54,451)	8,778
Total revenue and other operating income	1,265,814	863,852

(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 (see note 4)

Disaggregation of revenue from contracts with customers

	Year ended 31 December 2021 $'000		Year ended 31 December 2020 $'000
	North Sea	Malaysia	North Sea	Malaysia
Revenue from contracts with customers:
Revenue from crude oil sales	1,040,577	98,594	719,504	60,361
Revenue from gas and condensate sales⁽ⁱ⁾	242,708	1,365	57,930	2,556
Tariff revenue	654	-	15,074	-
Total revenue from contracts with customers	1,283,939	99,959	792,508	62,917

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

(b) Cost of sales

Accounting policy

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

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000
Production costs	292,252	265,529
Tariff and transportation expenses	39,414	63,685
Realised loss/(gain) on derivative contracts related to operating costs (see note 19)	(10,693)	(572)
Change in lifting position	62,868	(31,508)
Crude oil inventory movement	(561)	(3,293)
Depletion of oil and gas assets(i)	305,578	438,247
Other cost of operations(ii)	211,575	53,367
Business performance cost of sales	900,433	785,455
Unrealised (gains)/losses on derivative contracts related to operating costs(iii) (see note 19)	(472)	1,932
Movement in other provisions	7,673	11,694
Total cost of sales	907,634	799,081

(i) Includes $45.7 million (2020: $68.5 million) Kraken FPSO right-of-use asset depreciation charge and $14.3 million (2020: $10.5 million) of other right-of-use assets depreciation charge

(ii) Includes $199.6 million of purchases and associated costs of third-party gas not required for injection activities at Magnus which is sold on (2020: $24.7 million of inventory provisions and also includes purchases of third-party gas not required for injection activities at Magnus which is sold on)

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

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000
Staff costs (see note 5(f))	80,098	85,813
Depreciation(i)	7,492	7,616
Other general and administration costs	21,322	21,831
Recharge of costs to operations and joint venture partners	(108,549)	(109,155)
Total general and administration expenses	363	6,105

(i) Includes $4.0 million (2020: $3.7 million) right-of-use assets depreciation charge on buildings

(d) Other income

	Year ended 31 December 2021 $'000	Year ended 31 December restated⁽ⁱ⁾ 2020 $'000
Net foreign exchange gains	391	-
Gain on termination of Tanjong Baram risk service contract	-	10,209
Change in decommissioning provisions	19,327	-
Rental income from office sublease⁽ⁱ⁾	1,702	1,796
Other	9,570	6,095
Business performance other income	30,990	18,100
Fair value changes in contingent consideration (see note 22)	140,079	138,249
Other non-Business performance	22,568	-
Total other income	193,637	156,349

(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

(e) Other expenses

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000
Net foreign exchange losses	-	4,625
Change in decommissioning provisions	-	83,199
Change in Thistle decommissioning provisions (note 23)	6,184	11,998
Other	1,094	1,811
Business performance other expenses	7,278	101,633
Loss on derecognition of assets related to the Seligi riser detachment	-	956
Other non-Business performance	3,832	-
Total other expenses	11,110	102,589

(f) Staff costs

Accounting policy

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

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

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000
Wages and salaries	71,391	85,913
Social security costs	7,120	9,118
Defined contribution pension costs	5,464	6,871
Expense of share-based payments (see note 21)	6,351	3,401
Other staff costs	12,475	12,781
Total employee costs	102,801	118,084
Contractor costs	33,871	39,371
Total staff costs	136,672	157,455

General and administration staff costs (see note 5(c))	80,098	85,813
Non-general and administration costs	56,574	71,642
Total staff costs	136,672	157,455

The average number of persons, excluding contractors, employed by the Group during the year was 734, with 339 in the general and administration staff costs and 395 directly attributable to assets (2020: 885 of which 383 in general and administration and 502 directly attributable to assets). Compensation of key management personnel is disclosed in note 26 and in the remuneration report on page 84 of the annual report.

(g) Auditor's remuneration

The following amounts for the year ended 31 December 2021 and for the comparative year ended 31 December 2020 were payable by the Group to Deloitte:

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000
Fees payable to the Company's auditor for the audit of the parent company and Group financial statements	847	649
The audit of the Company's subsidiaries	145	178
Total audit	992	827
Audit-related assurance services(i)	1,419	180
Total audit and audit-related assurance services	2,411	1,007
Tax services	-	10
Total auditor's remuneration	2,411	1,017

(i) Audit-related assurance services include the review of the Group's interim results and audit and assurance work in respect of the Group's Golden Eagle acquisition

6. Finance costs/income

Accounting policy

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

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000
Finance costs:
Loan interest payable	20,206	32,791
Bond interest payable	69,085	73,476
Unwinding of discount on decommissioning provisions (see note 23)	15,856	14,512
Unwinding of discount on other provisions (see note 23)	1,061	796
Finance charges payable under leases	45,359	50,851
Amortisation of finance fees on loans and bonds	13,623	5,417
Other financial expenses	4,261	1,975
Business performance finance expenses	169,451	179,818
Finance costs on Magnus-related contingent consideration (see note 22)	58,395	77,259
Total finance costs	227,846	257,077
Finance income:
Bank interest receivable	228	896
Unwinding of discount on financial asset (see note 19(f))	-	275
Total finance income	228	1,171

7. Income tax

(a) Income tax

Accounting policy

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

The Group's operations are subject to a number of specific tax rules which apply to exploration, development and production. In addition, the tax provision is prepared before the relevant companies have filed their tax returns with the relevant tax authorities and, significantly, before these have been agreed. As a result of these factors, the tax provision process necessarily involves the use of a number of estimates and judgements including those required in calculating the effective tax rate. In considering the tax on exceptional items, the Group applies the appropriate statutory tax rate to each item to calculate the relevant tax charge on exceptional items.

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

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

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

Production taxes

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

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

Investment allowance

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

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

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 restated $'000
Current UK income tax
Current income tax charge	3,559	-
Adjustments in respect of current income tax of previous years	199	140
Current overseas income tax
Current income tax charge	18,050	2,424
Adjustments in respect of current income tax of previous years	(221)	(295)
Total current income tax	21,587	2,269
Deferred UK income tax
Relating to origination and reversal of temporary differences	(43,325)	(97,673)
Adjustments in respect of changes in tax rates	-	1
Adjustments in respect of deferred income tax of previous years	157	2,660
Deferred overseas income tax
Relating to origination and reversal of temporary differences	(5,320)	(5,135)
Adjustments in respect of deferred income tax of previous years	2,354	1,848
Total deferred income tax	(46,134)	(98,299)
Income tax (credit)/expense reported in profit or loss	(24,547)	(96,030)

(b) Reconciliation of total income tax charge

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

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 restated⁽ⁱ⁾ $'000
Profit/(loss) before tax	352,441	(565,975)
UK statutory tax rate applying to North Sea oil and gas activities of 40% (2020: 40%)	140,976	(226,390)
Supplementary corporation tax non-deductible expenditure	4,331	17,761
Petroleum revenue tax (net of income tax benefit)	2,548	(2,548)
Non-deductible expenditure/income	(1,442)	(3,449)
North Sea tax reliefs	(113,593)	(106,685)
Tax in respect of non-ring-fence trade	23,378	3,222
Deferred tax asset (recognition)/impairment in respect of non-ring-fence trade	21,241	3,515
Deferred tax asset (recognition)/impairment in respect of ring-fence trade	(104,546)	215,204
Adjustments in respect of prior years	2,489	4,352
Overseas tax rate differences	(594)	(1,250)
Share-based payments	1,526	1,097
Other differences	(861)	(859)
At the effective income tax rate of 7% (2020: 17%)	(24,547)	(96,030)

Deferred income tax relates to the following:

	Group balance sheet		(Credit)/charge for the year recognised in profit or loss
	2021 $'000	2020 restated⁽ⁱ⁾ $'000	2021 $'000	2020 restated⁽ⁱ⁾ $'000
Deferred tax liability
Accelerated capital allowances	768,630	821,253	(52,623)	(236,551)
	768,630	821,253
Deferred tax asset
Losses	(1,017,107)	(981,445)	(35,653)	121,089
Decommissioning liability	(286,045)	(310,697)	24,652	(26,640)
Other temporary differences	(165,030)	(182,529)	17,490	43,803
	(1,468,182)	(1,474,671)	(46,133)	(98,299)

Net deferred tax (assets)	(699,552)	(653,418)
Reflected in the balance sheet as follows:
Deferred tax assets	(702,970)	(659,803)
Deferred tax liabilities	3,418	6,385
Net deferred tax (assets)	(699,552)	(653,418)

Reconciliation of net deferred tax assets/(liabilities)

	2021 $'000	2020 restated⁽ⁱ⁾ $'000
At 1 January	653,418	555,119
Tax income/(expense) during the period recognised in profit or loss	46,134	98,299
At 31 December	699,552	653,418

(d) Tax losses

The Group's deferred tax assets at 31 December 2021 are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised. A $127.6 million tax credit has been recognised as an exceptional item, reflecting the reversal of the previous deferred tax asset derecognition. In accordance with IAS 12 Income Taxes, the Group assesses the recoverability of its deferred tax assets at each period end. Sensitivities have been run on the oil price assumption, with a 10% change being considered a reasonable possible change for the purposes of sensitivity analysis (see note 2). A 10% reduction in oil price would result in a deferred tax asset derecognition of $318.6 million and a 10% increase in oil price would result in an increase in deferred tax asset recognition of $107.9 million.

The Group has unused UK mainstream corporation tax losses of $431.7 million (2020: $320.7 million), and ring-fence tax losses of $957.8 million associated with the Bentley acquisition, for which no deferred tax asset has been recognised at the balance sheet date as recovery of these losses is to be established. In addition, the Group has not recognised a deferred tax asset for the adjustment to bond valuations on the adoption of IFRS 9. The benefit of this deduction is taken over ten years, with a deduction of $2.2 million being taken in the current period and the remaining benefit of $12.9 million (2020: $15.1 million) remaining unrecognised.

The Group has unused overseas tax losses in Canada of approximately CAD$13.5 million (2020: CAD$13.5 million) for which no deferred tax asset has been recognised at the balance sheet date. The tax losses in Canada have expiry periods of 20 years, none of which expire in 2021, and which arose following the change in control of the Stratic Group in 2010.

The Group has unused Malaysian income tax losses of $15.7 million (2020: $14.3 million) arising in respect of the Tanjong Baram RSC for which no deferred tax asset has been recognised at the balance sheet date due to uncertainty of recovery of these losses.

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

(e) Changes in legislation

The Finance Act 2020 enacted a change in the mainstream corporation tax rate to 19% with effect from 1 April 2020. As all UK mainstream corporation tax losses are not recognised there is minimal impact in 2020 resulting from this change. In the Budget statement on 3 March 2021, it was announced that the corporation tax rate will increase to 25% from 1 April 2023. This change is expected to have no impact.

8. Earnings per share

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

Basic and diluted earnings per share are calculated as follows:

	Profit/(loss) after tax		Weighted average number of Ordinary shares		Earnings per share
	Year ended 31 December		Year ended 31 December		Year ended 31 December
	2021 $'000	2020 restated⁽ⁱⁱ⁾ $'000	2021 million	2020 million	2021 $	2020 restated⁽ⁱⁱ⁾ $
Basic	376,988	(469,945)	1,736.4	1,655.0	0.217	(0.290)
Dilutive potential of Ordinary shares granted under share-based incentive schemes	-	-	24.7	15.1	-	-
Diluted(i)	376,988	(469,945)	1,761.1	1,670.1	0.214	(0.290)
Basic (excluding remeasurements and exceptional items)	220,284	(26,187)	1,736.4	1,655.0	0.127	(0.016)
Diluted (excluding remeasurements and exceptional items)(i)	220,284	(26,187)	1,761.1	1,670.1	0.125	(0.016)

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

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

9. Dividends paid and proposed

The Company paid no dividends during the year ended 31 December 2021 (2020: none). At 31 December 2021, there are no proposed dividends (2020: none).

10. Property, plant and equipment

Accounting policy

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

Cost

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

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

Development assets

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

Carry arrangements

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

Borrowing costs

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

Depletion and depreciation

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

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

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

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

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

Impairment of tangible and intangible assets (excluding goodwill)

At each balance sheet date, the Group assesses assets or groups of assets, called cash-generating units ('CGUs'), for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or CGU may not be recoverable. If any such indication exists, the Group makes an estimate of the asset's recoverable amount. An asset's recoverable amount is the higher of its fair value less costs of disposal and its value in use. Discounted cash flow models comprising asset-by-asset life of field projections and risks specific to assets, using Level 3 inputs (based on IFRS 13 fair value hierarchy), have been used to determine the recoverable amounts. The life of a field depends on the interaction of a number of variables such as the recoverable quantity of hydrocarbons, the production profile of the hydrocarbons, the capex necessary to recover the hydrocarbons, production costs and the selling price of the hydrocarbons produced. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure, are derived from the Group's business plan. Oil price assumptions and discount rate assumptions used were as disclosed in note 2. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. An impairment loss is recognised immediately in the Group income statement.

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

	Oil and gas assets $'000	Office furniture, fixtures and fittings $'000	Right-of-use assets (note 24) $'000	Total $'000
Cost:
At 1 January 2020	8,547,769	62,453	857,089	9,467,311
Additions	78,926	1,910	2,812	83,648
Change in decommissioning provision	10,200	-	-	10,200
Disposals and termination of Tanjong Baram risk service contract	(84,724)	(143)	(1,412)	(86,279)
At 1 January 2021	8,552,171	64,220	858,489	9,474,880
Acquisition	386,210	-	-	386,210
Additions	61,704	1,165	17,815	80,684
Change in decommissioning provision	(2,732)	-	-	(2,732)
Disposal	-	-	(8,411)	(8,411)
At 31 December 2021	8,997,353	65,385	867,893	9,930,631
Accumulated depreciation, depletion and impairment:
At 1 January 2020	5,797,924	46,568	171,890	6,016,382
Charge for the year	359,258	3,902	82,703	445,863
Disposals and termination of Tanjong Baram risk service contract	(42,958)	(113)	(706)	(43,777)
Impairment charge for the year	314,335	-	108,160	422,495
At 1 January 2021	6,428,559	50,357	362,047	6,840,963
Charge for the year	245,645	3,472	63,953	313,070
Net impairment reversal for the year	(24,046)	-	(15,669)	(39,715)
Disposal	-	-	(5,831)	(5,831)
Other	146	-	-	146
At 31 December 2021	6,650,304	53,829	404,500	7,108,633
Net carrying amount:
At 31 December 2021	2,347,049	11,556	463,393	2,821,998
At 31 December 2020	2,123,612	13,863	496,442	2,633,917
At 1 January 2020	2,749,845	15,885	685,199	3,450,929

The amount of borrowing costs capitalised during the year ended 31 December 2021 was nil (2020: nil).

Acquisitions

The Group acquired a 26.69% non-operated interest in the producing Golden Eagle area from Suncor Energy UK on 22 October 2021. The Group applied the optional concentration test for this transaction in accordance with IFRS 3. Accordingly, it has been concluded that as substantially all of the value arising from the transaction relates to the producing oil and gas asset, the acquired assets do not represent a business and therefore the transaction has been accounted for as an asset acquisition at cost. Consideration included cash of $249.7 million and a contingent payment based on the average oil price between July 2021 and June 2023. The Net Present Value of the contingent payment has been valued at $44.7 million and has been included within contingent consideration (see note 22). Other directly attributable costs of $10.4 million were also included in the cost of the acquisition. The total oil and gas asset recognised in relation to the acquisition is $386.2 million. A decommissioning liability of $119.3 million was also recognised as part of the acquisition (see note 23).

Impairments

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

	Impairment (charge)/reversal		Recoverable amount(i)
	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000	31 December 2021 $'000	31 December 2020 $'000
North Sea	39,715	(422,495)	1,496,219	1,518,832
Net pre-tax impairment reversal/(charge)	39,715	(422,495)

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

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

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

The 2020 impairment charge of $422.5 million related to producing assets in the UK North Sea. Impairment losses were primarily driven by a reduction in EnQuest's future oil price assumptions and the decision to cease production at Dons. The principal CGUs on which significant impairment losses were incurred in 2020 were $380.3 million for Kraken, $28.2 million for Alba and $14.6 million for Dons.

11. Goodwill

Accounting policy

Cost

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

Impairment of goodwill

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

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

A summary of goodwill is presented below:

	2021 $'000	2020 $'000
Cost and net carrying amount
At 1 January	134,400	134,400
At 31 December	134,400	134,400

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

Impairment testing of goodwill

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

The recoverable amounts of the CGU and fields have been determined on a fair value less costs of disposal basis. Discounted cash flow models comprising asset-by-asset life of field projections, based on current estimates of reserves and resources, and risks specific to assets, using Level 3 inputs (based on IFRS 13 fair value hierarchy), have been used to determine the recoverable amounts. The life of a field depends on the interaction of a number of variables such as the recoverable quantity of hydrocarbons, the production profile of the hydrocarbons, the capex necessary to recover the hydrocarbons, production costs and the selling price of the hydrocarbons produced. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure, are derived from the Group's business plan. Oil price assumptions and discount rate assumptions used were as disclosed in note 2. An impairment charge of nil was taken in 2021 (2020: nil) based on a fair value less costs to dispose valuation of the North Sea CGU, as described above.

Sensitivity to changes in assumptions

The Group's recoverable value of assets is highly sensitive, inter alia, to oil price achieved and production volumes. A sensitivity has been run on the oil price assumption, with a 10% change being considered to be a reasonable possible change for the purposes of sensitivity analysis (see note 2). A 10% reduction in oil price would result in a net impairment of $54.7 million (2020: 10% reduction would result in a net impairment of $14.0 million). A 20% reduction in oil price would fully impair goodwill (2020: 13%).

12. Intangible assets

Accounting policy

Exploration and appraisal assets

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

During the year ended 31 December 2021, there was no impairment of historical exploration and appraisal expenditures (2020: nil).

Other intangibles

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

	Exploration and appraisal assets $'000	UK emissions allowances $'000	Total $'000
Cost:
At 1 January 2020	174,964	-	174,964
Write-off of relinquished licences previously impaired	(12,645)	-	(12,645)
Other	(7)	-	(7)
At 1 January 2021	162,312	-	162,312
Additions	10,141	10,052	20,193
Write-off of relinquished licences previously impaired	(72)	-	(72)
At 31 December 2021	172,381	10,052	182,433
Accumulated impairment:
At 1 January 2020	(147,411)	-	(147,411)
Write-off of relinquished licences previously impaired	12,645	-	12,645
At 1 January 2021	(134,766)	-	(134,766)
At 31 December 2021	(134,766)	-	(134,766)
Net carrying amount:
At 31 December 2021	37,615	10,052	47,667
At 31 December 2020	27,546	-	27,546
At 1 January 2020	27,553	-	27,553

13. Inventories

Accounting policy

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

	2021 $'000	2020 $'000
Hydrocarbon inventories	22,835	20,509
Well supplies	50,188	39,275
	73,023	59,784

During 2021, a net gain of $0.4 million was recognised within cost of sales in the Group income statement relating to inventory (2020: charge of $21.6 million).

The inventory valuation at 31 December 2021 is stated net of a provision of $43.2 million (2020: $56.7 million) to write down well supplies to their estimated net realisable value. During the year a portion of the provided for well supplies was disposed of, resulting in a net charge to the income statement of $0.2 million (2020: $24.9 million).

14. Cash and cash equivalents

Accounting policy

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

	2021 $'000	2020 $'000
Available cash	276,970	221,155
Restricted cash	9,691	1,675
Cash and Cash Equivalents	286,661	22,830

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

Restricted cash

Included within the cash balance at 31 December 2021 is restricted cash of $9.7 million. This includes $8.2 million on deposit relating to bank guarantees for the Group's Malaysian assets and $1.5 million related to cash collateralised letters of credit. In 2020, the restricted cash balance of $1.7 million related to cash held in escrow in respect of the unwound acquisition of the Tunisian assets of PA resources. This balance was fully collected in 2021.

15. Financial instruments and fair value measurement

Accounting policy

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

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

Financial assets

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

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

Financial assets at amortised cost

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

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

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

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

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

Impairment of financial assets

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

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

Financial liabilities

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

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

Financial liabilities at amortised cost

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

Financial instruments at fair value through profit or loss

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

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

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

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

Fair value measurement

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

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

31 December 2020	Notes	Total $'000	Quoted prices in active markets (Level 1) $'000	Significant observable inputs (Level 2) $'000	Significant unobservable inputs (Level 3) $'000
Financial assets measured at fair value:
Other financial assets at FVPL
Quoted equity shares		7	7	-	-
Total financial assets measured at fair value		7	7	-	-
Liabilities measured at fair value:
Derivative financial liabilities at FVPL
Oil commodity derivative contracts	19	2,007	-	2,007	-
Other financial liabilities measured at FVPL
Contingent consideration	22	522,261	-	-	522,261
Total liabilities measured at fair value		524,268		2,007	522,261
Liabilities measured at amortised cost for which fair values are disclosed below:
Interest-bearing loans and borrowings	18	454,209	-	-	454,209
Obligations under leases	24	647,846	-	-	647,846
Retail bond	18	225,943	225,943	-	-
High yield bond	18	537,602	537,602	-	-
Total liabilities measured at amortised cost for which fair values are disclosed		1,865,600	763,545	-	1,102,055

Fair value hierarchy

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

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

Derivative financial instruments are valued by counterparties, with the valuations reviewed internally and corroborated with readily available market data (Level 2). Contingent consideration is measured at FVPL using the Level 3 valuation processes disclosed in note 22. There have been no transfers between Level 1 and Level 2 during the period (2020: no transfers).

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

16. Trade and other receivables

	2021 $'000	2020 $'000
Current
Trade receivables	94,992	24,604
Joint venture receivables	68,157	53,121
Under-lift position	35,769	15,690
VAT receivable	-	10,307
Other receivables	11,703	1,441
	210,621	105,163
Prepayments and accrued income	85,447	13,552
	296,068	118,715

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

Trade receivables are non-interest-bearing and are generally on 15 to 30-day terms. Joint venture receivables relate to amounts billable to, or recoverable from, joint venture partners. Receivables are reported net of any ECL with no losses recognised as at 31 December 2021 or 2020. The Group's ECL estimates were not significantly impacted by COVID-19 during 2021.

17. Trade and other payables

	2021 $'000	2020 $'000
Current
Trade payables	49,701	41,090
Accrued expenses	297,744	179,590
Over-lift position	53,742	12,732
Joint venture creditors	10,852	16,647
VAT payable	7,561	-
Other payables	944	5,096
	420,544	255,155

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

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

18. Loans and borrowings

	2021 $'000	2020 $'000
Borrowings	401,614	452,284
Bonds	1,081,596	1,045,041
	1,483,210	1,497,325

(a) Borrowings

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

	2021			2020
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
RBL	415,000	(23,250)	391,750	-	-	-
Credit facility	-	-	-	377,270	-	377,270
Sculptor Capital facility	-	-	-	67,701	(1,925)	65,776
SVT working capital facility	9,864	-	9,864	9,238	-	9,238
Total borrowings	424,864	(23,250)	401,614	454,209	(1,925)	452,284
Due within one year			210,505			414,430
Due after more than one year			191,109			37,854
Total borrowings			401,614			452,284

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

RBL facility

On 11 June 2021, the Group signed a new RBL facility of approximately $600.0 million and an additional amount of $150.0 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 the end of September 2023. In 2021 interest accrued at a rate of 4.25% plus USD LIBOR. From 1 January 2022, following the IBOR transition, interest will accrue at a rate of 4.25% plus a margin. The margin will be a combination of a fixed rate based on the interest period and SOFR. From October 2022, the fixed rate percentage will increase from 4.25% to 4.50%.

During 2021 the Group utilised $485.0 million of the RBL, $360.0 million in July and $125.0 million in October. In December 2021, the Group voluntarily repaid $70.0 million ahead of the planned amortisation schedule. As at 31 December 2021, the carrying value of the facility was $391.8 million, comprising the principal of $415.0 million and unamortised fees of $23.3 million.

At 31 December 2021, after allowing for letter of credit utilisation of $53.0 million, $32.0 million remained available for drawdown under the credit facility.

Credit facility

During the period, the Group repaid its outstanding debt on the Credit facility of $378.1 million.

Sculptor Capital facility

During the period, the Group repaid its outstanding debt on the Sculptor Capital facility of $67.7 million.

SVT working capital facility

On 1 December 2020, EnQuest extended, for a further three years, the £42.0 million revolving loan facility with a joint operator partner to fund the short-term working capital cash requirements on the acquisition of SVT and associated interests. The facility is guaranteed by BP EOC Limited. The facility is able to be drawn down against, in instalments, and accrues interest at 1.0% per annum plus GBP LIBOR.

(b) Bonds

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

	2021			2020
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
High yield bond	827,166	(1,725)	825,441	799,194	(2,666)	796,528
Retail bond	256,574	(419)	256,155	249,161	(648)	248,513
Total bonds due after more than one year	1,083,740	(2,144)	1,081,596	1,048,355	(3,314)	1,045,041

High yield bond

In April 2014, the Group issued a $650.0 million high yield bond. On 21 November 2016, the high yield bond was amended pursuant to a scheme of arrangement whereby all existing notes were exchanged for new notes. The new high yield notes continue to accrue a fixed coupon of 7.0% payable semi-annually in arrears. The interest is only payable in cash if the 'Cash Payment Condition' is satisfied, being the average of the Daily Brent Oil Prices during the period of six calendar months immediately preceding the 'Cash Payment Condition Determination Date' is equal to or above $65/bbl. The 'Cash Payment Condition Determination Date' is the date falling one calendar month prior to the relevant interest payment date. If the 'Cash Payment Condition' is not satisfied, interest will not be paid in cash but instead will be capitalised and satisfied through the issue of additional high yield notes ('Additional HY Notes'). $27.5 million of accrued, unpaid interest as at the restructuring date was capitalised and added to the principal amount of the new high yield notes issued pursuant to the scheme.

During 2020, the maturity date of the new high yield notes was automatically extended to 15 October 2023 as the credit facility had not been repaid or refinanced in full prior to 15 October 2020.

The above carrying value of the bond as at 31 December 2021 is $825.4 million (2020: $796.5 million). This includes bond principal of $827.2 million (2020: $799.2 million) less unamortised fees of $1.7 million (2020: $2.7 million). The high yield bond does not include accrued interest of $12.2 million (2020: $11.8 million) and liability for the IFRS 9 Financial Instruments loss on modification of $2.6 million (2020: $4.6 million), which are reported within trade and other payables. The fair value of the high yield bond is disclosed in note 15.

Retail bond

In 2013, the Group issued a £155.0 million retail bond. On 21 November 2016, the retail bond was amended pursuant to a scheme of arrangement whereby all existing notes were exchanged for new notes. The new retail notes continue to accrue a fixed coupon of 7.0% payable semi-annually in arrears. The interest is only payable in cash if the 'Cash Payment Condition' is satisfied, being the average of the Daily Brent Oil Prices during the period of six calendar months immediately preceding the 'Cash Payment Condition Determination Date' is equal to or above $65/bbl. The 'Cash Payment Condition Determination Date' is the date falling one calendar month prior to the relevant interest payment date. If the 'Cash Payment Condition' is not satisfied, interest will not be paid in cash but instead will be capitalised and satisfied through the issue of additional retail notes ('Additional Retail Notes').

During 2020, the maturity date of the new high yield notes was automatically extended to 15 October 2023 as the credit facility had not been repaid or refinanced in full prior to 15 October 2020.

The above carrying value of the bond as at 31 December 2021 is $256.2 million (2020: $248.5 million). This includes bond principal of $256.6 million (2020: $249.2 million) less unamortised fees of $0.4 million (2020: $0.6 million). The retail yield bond does not include accrued interest of $6.2 million (2020: $6.3 million) and liability for the IFRS 9 Financial Instruments loss on modification of $7.4 million (2020: $11.9 million), which are reported within trade and other payables. The fair value of the retail bond is disclosed in note 15.

19. Other financial assets and financial liabilities

(a) Summary as at year end

	2021		2020
	Assets $'000	Liabilities $'000	Assets $'000	Liabilities $'000
Fair value through profit or loss:
Derivative commodity contracts	-	55,245	-	2,007
Derivative foreign exchange contracts	382	-	-	-
Commodity futures	-	2	-	-
Derivative UKAs contracts	90	-	-	-
Total current	472	55,247	-	2,007
Fair value through profit or loss:
Quoted equity shares	6	-	7	-
Total non-current	6	-	7	-

(b) Income statement impact

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

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

Year ended 31 December 2020	Revenue and other operating income		Cost of sales
Year ended 31 December 2020	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	24,659	(136)	-	-
Commodity swaps	(36,912)	8,941	-	-
Commodity futures	6,194	(27)	-	-
Foreign exchange contracts	-	-	572	(1,932)
	(6,059)	8,778	572	(1,932)

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

For the year ended 31 December 2021, losses totalling $119.7 million (2020: gains of $2.7 million) were recognised in respect of commodity contracts designated as FVPL. This included losses totalling $65.3 million (2020: losses of $6.1 million) realised on contracts that matured during the year, and mark-to-market unrealised losses totalling $54.5 million (2020: gains of $8.8 million). Of the realised amounts recognised during the year, a loss of $1.0 million (2020: gain of $6.2 million) was realised in Business performance revenue in respect of the premium expense received on sale of these options.

The mark-to-market value of the Group's open commodity contracts as at 31 December 2021 was a liability of $55.2 million (2020: liability of $2.0 million).

(d) Foreign currency contracts

The Group enters into a variety of foreign currency contracts, primarily in relation to Sterling. During the year ended 31 December 2021, gains totalling $0.4 million (2020: losses of $1.4 million) were recognised in the Group income statement. This included realised gains totalling $0.1 million (2020: gains of $0.6 million) on contracts that matured in the year.

The mark-to-market value of the Group's open contracts as at 31 December 2021 was $0.4 million (2020: nil).

(e) UK emissions allowance forward contracts

The Group enters into forward contracts for the purchase of UKAs to manage its exposure to price. In 2020 these contracts were treated as own use contracts and not accounted for as derivatives. During 2021 a number of open contracts were closed out early. The result of this was the Group no longer being able to account for UKAs forwards as own use and recognising them as derivatives. During the year ended 31 December 2021, gains totalling $10.8 million (2020: nil) were recognised in the income statement. This included realised gains totalling $10.7 million (2020: nil) on contracts that matured in the year.

The mark-to-market value of the Group's open contracts as at 31 December 2021 was $0.1 million (2020: nil).

(f) Other receivables

	2021 $'000	2020 $'000
At 1 January	7	6,874
Change in fair value	(1)	(4)
Utilised during the year	-	(7,138)
Unwinding of discount	-	275
At 31 December	6	7

Non-current	6	7
	6	7

20. Share capital and premium

Accounting policy

Share capital and share premium

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

Retained earnings

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

Share-based payments reserve

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

Authorised, issued and fully paid	Ordinary shares of £0.05 each Number	Share capital $'000	Share premium $'000	Total $'000
At 1 January 2021	1,695,801,955	118,271	227,149	345,420
Issuance of equity shares	190,122,384	13,379	37,346	50,725
Expenses of issuance of equity shares	-	-	(3,949)	(3,949)
At 31 December 2021	1,885,924,339	131,650	260,546	392,196

At 31 December 2021, there were 39,718,323 shares held by the Employee Benefit Trust (2020: 46,492,546). On 26 July 2021, 2,159,903 shares were acquired by the Employee Benefit Trust pursuant to the firm placing, placing and open offer. The remaining movement in the year was due to shares used to satisfy awards made under the Company's share-based incentive schemes.

On 26 July 2021, the Group completed a firm placing, placing and open offer pursuant to which 190,122,384 new Ordinary shares were issued at a price of £0.19 per share, generating gross aggregate proceeds of $50.7 million. Following the admission to the market of an additional 190,122,384 Ordinary shares on 26 July 2021, there were 1,885,924,339 Ordinary shares in issue at the end of the year.

21. Share-based payment plans

Accounting policy

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

Information on these plans for Directors is shown in the Directors' remuneration report on pages 76 to 93 of the annual report.

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

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

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

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

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

	2021 $'000	2020 $'000
Performance Share Plan	5,241	3,277
Other performance share plans	135	364
Sharesave Plan	975	(240)
	6,351	3,401

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

Share plans	2021 Number	2020 Number
Outstanding at 1 January	110,263,670	77,374,961
Granted during the year	35,552,383	53,223,408
Exercised during the year	(8,056,525)	(6,288,132)
Forfeited during the year	(12,265,533)	(14,046,567)
Outstanding at 31 December	125,493,995	110,263,670
Exercisable at 31 December	14,249,920	11,894,904

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

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

	2021		2020
Share options	Number	Weighted average exercise price $	Number	Weighted average exercise price $
Outstanding at 1 January	42,383,654	0.13	42,589,522	0.16
Granted during the year	1,370,748	0.25	34,719,941	0.13
Exercised during the year	(885,646)	0.10	(452,545)	0.14
Forfeited during the year	(5,349,829)	0.15	(34,473,264)	0.17
Outstanding at 31 December	37,518,927	0.14	42,383,654	0.13
Exercisable at 31 December	422,981	0.16	449,912	0.15

22. Contingent consideration

Accounting policy

When the consideration transferred by the Group in a business combination includes a contingent consideration arrangement, the contingent consideration is measured at its acquisition-date fair value and included as part of the consideration transferred in a business combination. Changes in fair value of the contingent consideration that qualify as measurement period adjustments are adjusted retrospectively, with corresponding adjustments against goodwill. Measurement period adjustments are adjustments that arise from additional information obtained during the 'measurement period' (which cannot exceed one year from the acquisition date) about facts and circumstances that existed at the acquisition date.

The subsequent accounting for changes in the fair value of the contingent consideration that do not qualify as measurement period adjustments depends on how the contingent consideration is classified. Contingent consideration that is classified as equity is not remeasured at subsequent reporting dates and its subsequent settlement is accounted for within equity. Other contingent consideration is remeasured to fair value at subsequent reporting dates with changes in fair value recognised in profit or loss.

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

	Magnus 75% $'000	Magnus decommissioning-linked liability $'000	Golden Eagle $'000	Total $'000
At 31 December 2020	507,660	14,601	-	522,261
Additions	-	-	44,668	44,668
Change in fair value (see note 5(d))	(145,273)	5,194	-	(140,079)
Unwinding of discount (see note 6)	50,766	1,460	507	52,733
Interest on vendor loan (see note 6)	6,169	-	-	6,169
Utilisation	(74,695)	(279)	-	(74,974)
At 31 December 2021	344,627	20,976	45,175	410,778
Classified as:
Current	26,225	4,252	-	30,477
Non-current	318,402	16,724	45,175	380,301
	344,627	20,976	45,175	410,778

75% Magnus acquisition contingent consideration

On 1 December 2018, EnQuest completed the acquisition of the additional 75% interest in the Magnus oil field ('Magnus') and associated interests (collectively the 'Transaction assets') which was part funded through a vendor loan and profit share arrangement with BP. This acquisition followed on from the acquisition of initial interests completed in December 2017.

The consideration for the acquisition was $300.0 million, consisting of $100.0 million cash contribution, paid from the funds received through the rights issue undertaken in October 2018, and $200.0 million deferred consideration financed by BP. The deferred consideration financed by BP was fully settled in June 2021. The consideration also included a contingent profit-sharing arrangement whereby EnQuest and BP share the net cash flow generated by the 75% interest on a 50:50 basis, subject to a cap of $1 billion received by BP. Together, the deferred consideration and contingent profit-sharing arrangement are known as contingent consideration. The contingent consideration is a financial liability classified as measured at fair value through profit or loss. The fair value of contingent consideration has been determined by calculating the present value of the future expected cash flows expected to be paid and is considered a level 3 valuation under the fair value hierarchy. Future cash flows are estimated based on inputs including future oil prices, production volumes and operating costs. Oil price assumptions and discount rate assumptions used were as disclosed in Use of judgements, estimates and assumptions within note 2. The contingent consideration was fair valued at 31 December 2021, which resulted in a decrease in fair value of $145.3 million (2020: decrease of $137.4 million). The decrease in fair value in 2021 is a result of revised operating cost assumptions. The decrease in 2020 reflected the change in oil price assumptions. The fair value accounting effect and finance costs of $57.0 million (2020: $77.3 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 in 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: $41.1 million), is disclosed separately under investing activities; the repayment of the vendor loan, $73.7 million (2020: $20.7 million), is disclosed under financing activities; and the interest paid on the vendor loan, $6.2 million (2020: $10.3 million), is included within interest paid under financing activities. As part of the Golden Eagle area transaction, the repayment of the vendor loan was completed in July 2021. At 31 December 2021, the contingent consideration for Magnus was $344.6 million (31 December 2020: $507.7 million).

Management has considered alternative scenarios to assess the valuation of the contingent consideration including, but not limited to, the key accounting estimate relating to the oil price and the interrelationship with production and the profit share arrangement. As detailed in key accounting estimates, a reduction or increase in the price assumptions of 10% are considered to be reasonably possible changes, resulting in a reduction of $85.1 million or an increase of $85.1 million to the contingent consideration, respectively (2020: reduction of $91.7 million and increase of $91.7 million, respectively). The change in value represents a change in timing of cash flows, with the contingent profit-sharing arrangement cap of $1 billion not met in either sensitivity.

The payment of contingent consideration is limited to cash flows generated from Magnus. Therefore, no contingent consideration is payable if insufficient cash flows are generated over and above the requirements to operate the asset. By reference to the conditions existing at 31 December 2021, the maturity analysis of the loan is disclosed in Risk management and financial instruments - liquidity risk (note 27).

Magnus decommissioning-linked contingent consideration

As part of the Magnus and associated interests acquisition, BP retained the decommissioning liability in respect of the existing wells and infrastructure and EnQuest agreed to pay additional consideration in relation to the management of the physical decommissioning costs of Magnus. At 31 December 2021, the amount due to BP calculated on an after-tax basis by reference to 30% of BP's decommissioning costs on Magnus was $21.0 million (2020: $14.6 million).

Golden Eagle contingent consideration

On 22 October 2021, the Group completed the acquisition of the entire 26.69% non-operated working interest in the Golden Eagle Area Development, comprising the producing Golden Eagle, Peregrine and Solitaire fields (see note 10). The consideration for the acquisition included an amount that was contingent on the average oil price between July 2021 and June 2023. The contingent consideration is payable in the second half of 2023, if between July 2021 and June 2023 the Dated Brent average crude price equals or exceeds $55/bbl, upon which $25.0 million is payable, or if the Dated Brent average crude price equals or exceeds $65/bbl, upon which $50.0 million is payable. The contingent consideration liability is discounted at 7% and is calculated principally based on the oil price assumptions as disclosed in note 2. At 31 December 2021, the contingent consideration was valued at $45.2 million.

23. Provisions

Accounting policy

Decommissioning

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

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

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

Other

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

	Decommissioning provision $'000	Thistle decommissioning provision $'000	Other provisions $'000	Total $'000
At 31 December 2020	778,204	53,066	9,137	840,407
Additions during the year	119,312	-	13,390	132,702
Changes in estimates	(22,059)	6,184	(264)	(16,139)
Unwinding of discount	15,856	1,061	-	16,917
Utilisation	(55,594)	(16,553)	(6,970)	(79,117)
Foreign exchange	2	172	(2)	172
At 31 December 2021	835,721	43,930	15,291	894,942
Classified as:
Current	116,229	9,156	15,291	140,676
Non-current	719,492	34,774	-	754,266
	835,721	43,930	15,291	894,942

Decommissioning provision

The Group's total provision represents the present value of decommissioning costs which are expected to be incurred up to 2048, assuming no further development of the Group's assets. Additions during the year relate to the decommissioning provision recognised as part of the Golden Eagle acquisition. At 31 December 2021, an estimated $409.6 million is expected to be utilised between one and five years (2020: $329.2 million), $81.4 million within six to ten years (2020: $145.1 million), and the remainder in later periods.

The Group enters into surety bonds principally to provide security for its decommissioning obligations. The surety bond facilities which expired in December 2020 were renewed for 12 months, subject to ongoing compliance with the terms of the Group's borrowings. At 31 December 2021, the Group held surety bonds totalling $240.8 million (2020: $151.7 million).

Thistle decommissioning provision

In 2017, EnQuest had the option to receive $50.0 million from BP in exchange for undertaking the management of the physical decommissioning activities for Thistle and Deveron and making payments by reference to 7.5% of BP's share of decommissioning costs of Thistle and Deveron fields. The option was exercised in full during 2018 and the liability recognised within provisions. At 31 December 2021, the amount due to BP by reference to 7.5% of BP's decommissioning costs on Thistle and Deveron was $43.9 million (2020: $53.1 million). Unwinding of discount of $1.1 million is included within finance income for the year ended 31 December 2021 (2020: $0.8 million).

Other provisions

During 2020, a riser at the Seligi Alpha platform which provides gas lift and injection to the Seligi Bravo platform detached. A provision with respect to required repairs to remedy the damage caused was established. During 2021, $4.4 million was utilised and at 31 December 2021, the provision was $1.5 million (31 December 2020: $5.9 million).

During 2021, the Group recognised $8.2 million in relation to disputes with third-party contractors. The Group expects the dispute to be settled in 2022.

Other provisions from 31 December 2020 were fully utilised in the year. 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).

24. Leases

Accounting policy

As a lessee

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

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

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

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

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

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

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

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

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

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

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

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

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

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

As a lessor

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

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

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

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

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

Right-of-use assets and lease liabilities

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

	Right-of-use assets $'000	Lease liabilities $'000
As at 31 December 2019	685,199	716,166
Additions in the period	2,812	2,812
Depreciation expense	(82,703)	-
Impairment	(108,160)	-
Disposal	(706)	(726)
Interest expense	-	50,851
Payments	-	(123,001)
Foreign exchange movements	-	1,744
As at 31 December 2020	496,442	647,846
Additions in the period (see note 10)	17,815	17,815
Depreciation expense (see note 10)	(63,953)	-
Impairment reversal (see note 10)	15,669	-
Disposal	(2,580)	(3,121)
Interest expense	-	45,359
Payments	-	(136,651)
Foreign exchange movements	-	(467)
As at 31 December 2021	463,393	570,781
Current		128,281
Non-current		442,500
		570,781

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

Amounts recognised in profit or loss

	Year ended 31 December 2021 $'000	Year ended 31 December 2020 $'000
Depreciation expense of right-of-use assets	63,953	82,703
Interest expense on lease liabilities	45,359	50,851
Rent expense - short-term leases	1,028	12,736
Rent expense - leases of low-value assets	5	43
Total amounts recognised in profit or loss	110,345	146,333

Amounts recognised in statement of cash flows

Year ended

31 December

2021

$'000

Year ended

31 December

2020
$'000

Total cash outflow for leases

136,651

123,001

Leases as lessor

The Group sub-leases part of Annan House, the Aberdeen office. The sub-lease is classified as an operating lease, as all the risks and rewards incidental to the ownership of the right-of-use asset are not all substantially transferred to the lessee. Rental income recognised by the Group during 2021 was $1.7 million (2020: $1.7 million).

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

	2021 $'000	2020 $'000
Less than one year	2,206	2,211
One to two years	2,206	2,211
Two to three years	2,206	2,211
Three to four years	2,206	2,211
Four to five years	2,206	1,508
More than five years	1,204	1,093
Total undiscounted lease payments	12,234	11,444

25. Commitments and contingencies

Capital commitments

At 31 December 2021, the Group had capital commitments amounting to $1.9 million (2020: nil).

Other commitments

In the normal course of business, the Group will obtain surety bonds, letters of credit and guarantees. At 31 December 2021, the Group held surety bonds totalling $240.8 million (2020: $151.7 million) to provide security for its decommissioning obligations. See note 23 for further details.

Contingencies

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

26. Related party transactions

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

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

All sales to and purchases from related parties are made at normal market prices and the pricing policies and terms of these transactions are approved by the Group's management. With the exception of the transactions disclosed below, there have been no transactions with related parties who are not members of the Group during the year ended 31 December 2021 (2020: none).

Office sub-lease

During the year ended 31 December 2021, the Group recognised nil (2020: $0.1 million) rental income in respect of an office sub-lease arrangement with Levendi Investment Management Limited, a company where 72% of the issued share capital is held by Amjad Bseisu.

Compensation of key management personnel

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

	2021 $'000	2020 $'000
Short-term employee benefits	6,890	7,576
Share-based payments	810	107
Post-employment pension benefits	215	224
	7,915	7,907

27. Risk management and financial instruments

Risk management objectives and policies

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

The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. Management reviews and agrees policies for managing each of these risks, which are summarised below. Also presented below is a sensitivity analysis to indicate sensitivity to changes in market variables on the Group's financial instruments and to show the impact on profit and shareholders' equity, where applicable. The sensitivity has been prepared for periods ended 31 December 2021 and 2020, using the amounts of debt and other financial assets and liabilities held at those reporting dates.

Commodity price risk - oil prices

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

The Group's policy is to have the ability to hedge oil prices up to a maximum of 75% of the next 12 months' production on a rolling annual basis, up to 60% in the following 12-month period and 50% in the subsequent 12-month period. On a rolling quarterly basis, under the RBL, the Group is required to hedge a minimum of 60% of volumes of net entitlement production expected to be produced in the next 12 months, 40% of volumes of net entitlement produced expected for following 12 months and 10% of volumes of net entitlement production expected to be produced in the subsequent period. This requirement ceases at the end date of the facility.

Details of the commodity derivative contracts entered into during and open at the end of 2021 are disclosed in note 19. As of 31 December 2021, the Group held financial instruments (options and swaps) related to crude oil that covered 8.0 MMbbls of 2022 production and 3.5 MMbbls of 2023 production. The instruments have an effective average floor price of around $62.5/bbl in 2022 and $57.5/bbl in 2023. The Group utilises multiple benchmarks when hedging production to achieve optimal results for the Group. No derivatives were designated in hedging relationships at 31 December 2021.

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

	Pre-tax profit
	+$10/bbl increase $'000	-$10/bbl decrease $'000
31 December 2021	(91,755)	55,267
31 December 2020	(8,020)	1,365

Foreign exchange risk

The Group is exposed to foreign exchange risk arising from movements in currency exchange rates. Such exposure arises from sales or purchases in currencies other than the Group's functional currency and the retail bond which is denominated in Sterling. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of the non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged. Approximately 18% (2020: 8%) of the Group's sales and 89% (2020: 86%) of costs (including operating and capital expenditure and general and administration costs) are denominated in currencies other than the functional currency.

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

Year ended 31 December 2021

GBP

$'000

MYR

$'000

Other

$'000

Total

$'000

Total financial assets

103,253

34,255

3,967

141,475

Total financial liabilities

635,840

21,058

839

657,737

Year ended 31 December 2020

GBP

$'000

MYR

$'000

Other

$'000

Total

$'000

Total financial assets

32,150

11,735

2,777

46,662

Total financial liabilities

519,060

23,931

869

543,860

The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact in equity is the same as the impact on profit before tax. The Group's exposure to foreign currency changes for all other currencies is not material:

	Pre-tax profit
	+$10% rate increase $'000	-$10% rate decrease $'000
31 December 2021	(50,695)	50,695
31 December 2020	(46,183)	46,183

Credit risk

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

In addition, there are credit risks of commercial counterparties including exposures in respect of outstanding receivables. The Group trades only with recognised international oil and gas companies, commodity traders and shipping companies and at 31 December 2021 there were $0.2 million of trade receivables past due (2020: $2.6 million) and nil of joint venture receivables past due (2020: $2.5 million) but not impaired. Subsequent to the year end, $0.1 million of these outstanding balances have been collected (2020: $4.4 million). Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary. The impact of ECL is disclosed in note 16.

Ageing of past due but not impaired receivables	2021 $'000	2020 $'000
Less than 30 days	-	2,974
30-60 days	30	1,335
60-90 days	146	164
90-120 days	-	271
120+ days	-	383
	176	5,127

At 31 December 2021, the Group had one customer accounting for 84% of outstanding trade receivables (2020: three customers, 77%) and one joint venture partner accounting for 20% of outstanding joint venture receivables (2020: one joint venture partner, 16%).

Liquidity risk

The Group monitors its risk of a shortage of funds by reviewing its cash flow requirements on a regular basis relative to its existing bank facilities and the maturity profile of its borrowings. Specifically, the Group's policy is to ensure that sufficient liquidity or committed facilities exist within the Group to meet its operational funding requirements and to ensure the Group can service its debt and adhere to its financial covenants. At 31 December 2021, $32.0 million (2020: $61.2 million) was available for drawdown under the Group's facilities (see note 18).

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

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

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

Year ended 31 December 2020	On demand $'000	Up to 1 year $'000	1 to 2 years $'000	2 to 5 years $'000	Over 5 years $'000	Total $'000
Loans and borrowings	-	430,289	39,778	-	-	470,067
Bonds(i)	-	-	-	1,255,474	-	1,255,474
Contingent considerations	-	78,219	77,055	254,319	401,259	810,852
Obligations under finance leases	-	133,765	130,667	337,177	217,013	818,622
Trade and other payables	-	249,111	117	-	-	249,228
	-	891,384	247,617	1,846,970	618,272	3,604,243

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

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

Year ended 31 December 2021

On demand

$'000

Less than

3 months

$'000

3 to 12 months

$'000

1 to 2 years

$'000

Over 2 years

$'000

Total

$'000

Commodity derivative contracts

4,450

17,288

24,035

15,746

61,519

4,450

17,288

24,035

15,746

61,519

Year ended 31 December 2020

On demand

$'000

Less than

3 months

$'000

3 to 12 months

$'000

1 to 2 years

$'000

Over 2 years

$'000

Total

$'000

Commodity derivative contracts

3,108

2,007

5,115

3,108

2,007

5,115

Capital management

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

The primary objective of the Group's capital management is to optimise the return on investment, by managing its capital structure to achieve capital efficiency whilst also maintaining flexibility. The Group regularly monitors the capital requirements of the business over the short, medium and long term, in order to enable it to foresee when additional capital will be required.

The Group has approval from the Board to hedge external risks, see Commodity price risk - oil prices and Foreign exchange risk. This is designed to reduce the risk of adverse movements in exchange rates and market prices eroding the return on the Group's projects and operations.

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

The Group monitors capital using the gearing ratio and return on shareholders' equity as follows. Further information relating to the movement year-on-year is provided within the relevant notes and within the Financial review (pages 10 to 16).

	2021 $'000	2020 restated $'000
Loans, borrowings and bond(i) (A) (see note 18)	1,508,604	1,502,564
Cash and short-term deposits (see note 14)	(286,661)	(222,830)
Net debt (B)	1,221,943	1,279,734
Equity attributable to EnQuest PLC shareholders (C)	543,766	(207,377)
Profit/(loss) for the year attributable to EnQuest PLC shareholders (D)	376,988	(469,927)
Profit/(loss) for the year attributable to EnQuest PLC shareholders excluding exceptionals (E)	220,284	(26,187)
Adjusted EBITDA (F)	742,868	550,606
Gross gearing ratio (A/C)	2.8	n/a
Net gearing ratio (B/C)	2.2	n/a
Net debt/Adjusted EBITDA (B/F)	1.6	2.3
Shareholders' return on investment (D/C)	74%	n/a
Shareholders' return on investment excluding exceptionals (E/C)	41%	n/a

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

28. Subsidiaries

At 31 December 2021, EnQuest PLC had investments in the following subsidiaries:

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

(i) Held by subsidiary undertaking

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

Registered office addresses:

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

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

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

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

29. Cash flow information

Cash generated from operations

	Notes	Year ended 31 December 2021 $'000	Year ended 31 December 2020 restated⁽ⁱ⁾ $'000
Profit/(loss) before tax		352,441	(565,975)
Depreciation	5(c)	7,492	7,616
Depletion	5(b)	305,578	438,247
Net impairment (reversal)/charge to oil and gas assets	4	(39,715)	422,495
Write down of inventory		151	24,940
Change in fair value of investments		1	4
Share-based payment charge	5(f)	6,351	3,401
Gain on termination of Tanjong Baram risk service contract	5(d)	-	(10,209)
Loss on derecognition of assets related to the Seligi riser detachment	5(e)	-	956
Change in Magnus related contingent consideration	22	(81,684)	(60,991)
Change in provisions	23	16,900	119,642
Other non-cash income	5(d)	(22,568)	-
Other expense on final settlement relating to the Magnus acquisition	5(e)	3,832	-
Change in Golden Eagle related contingent consideration	22	507	-
Option premiums	19	1,030	(6,226)
Unrealised (gain)/loss on commodity financial instruments	5(a)	54,451	(8,778)
Unrealised (gain)/loss on other financial instruments	5(b)	(472)	1,932
Unrealised exchange loss/(gain)		(425)	5,067
Net finance expense		152,306	163,339
Operating profit before working capital changes		756,176	535,460
Decrease/(increase) in trade and other receivables		(171,946)	184,560
(Increase)/decrease in inventories		(13,496)	(5,438)
(Decrease)/increase in trade and other payables		186,194	(147,417)
Cash generated from operations		756,928	567,165

(i) 2020 comparative restated. 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 1 January 2020	(661,282)	(995,983)	(716,166)	(2,373,431)
Cash movements:
Repayments of loans and borrowings	210,671	-	-	210,671
Repayment of lease liabilities	-	-	123,001	123,001
Cash interest paid in year	31,056	-	-	31,056
Non-cash movements:
Additions	-	-	(2,812)	(2,812)
Interest/finance charge payable	(32,791)	(73,476)	(50,851)	(157,118)
Fee amortisation	(849)	(2,261)	-	(3,110)
Foreign exchange adjustments	(77)	(7,923)	(1,744)	(9,744)
Disposal	-	-	726	726
Other non-cash movements	498	(49)	-	449
At 31 December 2020	(452,774)	(1,079,692)	(647,846)	(2,180,312)
Cash movements:
Repayments of loans and borrowings	184,276	-	-	184,276
Drawdowns of loans and borrowings	(125,000)	-	-	(125,000)
Repayment of lease liabilities	-	-	136,651	136,651
Cash interest paid in year	19,428	38,154	-	57,582
Non-cash movements:
Additions	2,082	-	(17,815)	(15,733)
Interest/finance charge payable	(20,206)	(69,085)	(45,359)	(134,650)
Fee amortisation	(9,857)	(1,173)	-	(11,030)
Disposal	-	-	3,121	3,121
Foreign exchange and other non-cash movements	(14)	1,876	467	2,329
At 31 December 2021	(402,065)	(1,109,920)	(570,781)	(2,082,766)

Reconciliation of carrying value

	Loans and borrowings (see note 18) $'000	Bonds (see note 18) $'000	Lease liabilities (see note 24) $'000	Total $'000
Principal	(454,209)	(1,048,355)	(647,846)	(2,150,410)
Unamortised fees	1,925	3,314	-	5,239
Accrued interest (note 17)	(490)	(34,651)	-	(35,141)
At 31 December 2020	(452,774)	(1,079,692)	(647,846)	(2,180,312)
Principal	(424,864)	(1,083,740)	(570,781)	(2,079,385)
Unamortised fees	23,250	2,144	-	25,394
Accrued interest (note 17)	(451)	(28,324)	-	(28,775)
At 31 December 2021	(402,065)	(1,109,920)	(570,781)	(2,082,766)

Glossary - Non-GAAP measures

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

The use of the business performance APM is explained in note 2 of the Group's consolidated financial statements on page 32.

Business performance net profit attributable to EnQuest PLC shareholders	2021 $'000	2020 restated $'000
Reported net profit/(loss) (A)	376,988	(469,945)
Adjustments - remeasurements and exceptional items (note 4):
Unrealised (losses)/gains on derivative contracts (note 19)	(53,979)	6,846
Net impairment (charge)/reversal to oil and gas assets (note 10, note 11 and note 12)	39,715	(422,495)
Finance costs on Magnus contingent consideration (note 6)	(58,395)	(77,259)
Change in Magnus contingent consideration (note 5(d))	140,079	138,249
Movement in other provisions	(7,673)	(11,694)
Loss on derecognition of assets related to the Seligi riser detachment (note 5(e))	-	(956)
Other exceptional income (note 5(d))	22,568	-
Other exceptional expenses (note 5(e))	(3,832)	-
Pre-tax remeasurements and exceptional items (B)	78,483	(367,309)
Tax on remeasurements and exceptional items (C)	78,221	(76,449)
Post-tax remeasurements and exceptional items (D = B + C)	156,704	(443,758)
Business performance net profit attributable to EnQuest PLC shareholders (A - D)	220,284	(26,187)

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

Adjusted EBITDA	2021 $'000	2020 $'000
Reported profit/(loss) from operations before tax and finance income/(costs)	580,059	(310,069)
Adjustments:
Remeasurements and exceptional items (note 4)	(136,878)	290,050
Depletion and depreciation (note 5(b) and note 5(c))	313,070	445,863
Inventory revaluation	151	24,940
Change in provision (note 5(d) and note 5(e))	(13,143)	95,197
Net foreign exchange (gain)/loss (note 5(d) and note 5(e))	(391)	4,625
Adjusted EBITDA (E)	742,868	550,606

Total cash and available facilities is a measure of the Group's liquidity at the end of the reporting period. The Group believes this is a useful metric as it is an important reference point for the Group's going concern and viability assessments, see pages 14 to 16.

Total cash and available facilities	2021 $'000	2020 $'000
Available cash	276,970	221,155
Restricted cash	9,691	1,675
Total cash and cash equivalents (F) (note 14)	286,661	222,830

Available credit facilities	500,000	450,000
Credit facility - drawn down	(415,000)	(360,000)
Letter of credit (note 18)	(53,000)	(28,778)
Available undrawn facility (G)	32,000	61,222
Total cash and available facilities (F + G)	318,661	284,052

Net debt is a liquidity measure that shows how much debt a company has on its balance sheet compared to its cash and cash equivalents. With de-leveraging a strategic priority, the Group believes this is a useful metric to demonstrate progress in this regard. It is also an important reference point for the Group's going concern and viability assessments, see pages 14 to 16.

Net debt	2021 $'000	2020 $'000
Borrowings (note 18):
RBL	391,750	-
Credit facility	-	377,270
Sculptor Capital facility	-	65,776
SVT working capital facility	9,864	9,238
Borrowings (H)	401,614	452,284
Bonds (note 18):
High yield bond	825,441	796,528
Retail bond	256,155	248,513
Bonds (I)	1,081,596	1,045,041
Non-cash accounting adjustments (note 18):
Unamortised fees on loans and borrowings	23,250	1,925
Unamortised fees on bonds	2,144	3,314
Non-cash accounting adjustments (J)	25,394	5,239
Debt (H + I + J) (K)	1,508,604	1,502,564
Less: Cash and cash equivalents (note 14) (E)	286,661	222,830
Net debt/(cash) (K - F) (L)	1,221,943	1,279,734

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

Net debt/Adjusted EBITDA	2021 $'000	2020 $'000
Net debt (L)	1,221,943	1,279,734
Adjusted EBITDA (E)	742,868	550,606
Net debt/Adjusted EBITDA (L/E)	1.6	2.3

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

Cash capex and Cash capital and abandonment expense	2021 $'000	2020 $'000
Reported net cash flows (used in)/from investing activities	(321,230)	(120,597)
Adjustments:
Purchase of other intangible assets	10,052	-
Repayment of Magnus contingent consideration - Profit share	968	41,071
Net cash received on termination of Tanjong Baram risk service contract	-	(51,054)
Acquisition costs	258,627	-
Interest received	(256)	(796)
Cash capex	(51,839)	(131,376)
Decommissioning spend	(65,791)	(41,605)
Cash capital and abandonment expense	(117,630)	(172,981)

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

During 2021, the Group updated the definition of FCF to adjust for the impact of share issues and acquisitions. The definition of free cash flow is now net cash flow adjusted for net repayment/proceeds of loans and borrowings, net proceeds of share issues and cost of acquisitions.

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

Free cash flow	2021 $'000	2020 restated $'000
Net cash flows from/(used in) operating activities	674,138	521,420
Net cash flows from/(used in) investing activities	(321,230)	(120,597)
Net cash flows from/(used in) financing activities	(285,474)	(401,014)
Adjustments:
Proceeds of loans and borrowings	(125,000)	-
Repayment of loans and borrowings	184,276	210,671
Acquisitions	258,627	-
Repayment of Magnus contingent consideration - Vendor loan⁽ⁱ⁾	58,668	-
Net proceeds from share issue	(47,782)	-
Shares purchased by Employee Benefit Trust	576	-
Free cash flow	396,799	210,480

(i) Related to the accelerated vendor loan repayment

Revenue sales	2021 $'000	2020 $'000
Revenue from crude oil sales (note 5(a)) (M)	1,139,171	779,865
Revenue from gas and condensate sales (note 5(a)) (N)	244,073	60,486
Realised (losses)/gains on oil derivative contracts (note 5(a)) (P)	(67,679)	(6,059)

Barrels equivalent sales	2021 kboe	2020 kboe
Sales of crude oil (Q)	15,609	18,758
Sales of gas and condensate(i)	2,829	3,471
Total sales (R)	18,438	22,229

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

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

Average realised prices	2021 $/Boe	2020 $/Boe
Average realised oil price, excluding hedging (M/Q)	73.0	41.6
Average realised oil price, including hedging ((M + P)/Q)	68.6	41.3
Average realised blended price, excluding hedging ((M + N)/R)	75.0	37.8
Average realised blended price, including hedging ((M + N + P)/R)	71.4	37.5

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

Operating costs	2021 $'000	2020 $'000
Reported cost of sales (note 5(b))	907,634	799,081
Adjustments:
Remeasurements and exceptional items (note 5(b))	(7,201)	(13,626)
Depletion of oil and gas assets (note 5(b))	(305,578)	(438,247)
(Credit)/charge relating to the Group's lifting position and inventory (note 5(b))	(62,307)	34,801
Other cost of operations (note 5(b))	(211,575)	(53,367)
Operating costs	320,973	328,642
Less realised (gain)/loss on derivative contracts (S) (note 5(b))	10,693	572
Operating costs directly attributable to production	331,666	329,214
Comprising of:
Production costs (T) (note 5(b))	292,252	265,529
Tariff and transportation expenses (U) (note 5(b))	39,414	63,685
Operating costs directly attributable to production	331,666	329,214

Barrels equivalent produced

2021

kboe

2020

kboe

Total produced (working interest) (V)

16,211

21,636

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

Unit opex	2021 $/Boe	2020 $/Boe
Production costs (T/V)	18.1	12.3
Tariff and transportation expenses (U/V)	2.4	2.9
Total unit opex ((T + U)/V)	20.5	15.2
Realised (gain)/loss on derivative contracts (S/V)	(0.7)	-
Total unit opex including hedging ((S + T+ U)/V)	19.8	15.2

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Date	24 Mar 2022
Time	07:01:01
Category	Results
ID	8360F

Date	24 Mar 2022
Time	07:01:01
Category	Results
ID	8360F