EnQuest PLC

Results for the six months ended 30 June 2022

6 September 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 30 June 2021 and the Balance Sheet as at 31 December 2021. Alternative performance measures are reconciled within the 'Glossary - Non-GAAP measures' at the end of the Financial Statements.

 

EnQuest Chief Executive, Amjad Bseisu, said:

"Strong production, together with high commodity prices saw the Group generate free cash flow totalling $332 million in the first half of 2022, driving a significant reduction in net debt to $880 million. Consequently, our net debt to 12-month EBITDA ratio has reduced to 0.9x, demonstrating excellent progress towards our 0.5x target.

"We have a significant work programme to deliver in the second half of the year but remain on track to deliver our operational targets in our core business.

"We are also committed to supporting the UK's twin objectives of delivering energy security and decarbonisation. Through our Infrastructure and New Energy business, we intend to repurpose and utilise existing assets to progress new energy and decarbonisation opportunities, including carbon capture and storage, electrification, and the production of green hydrogen.

"We remain focused on further strengthening our balance sheet, which will position us well to utilise our capability to unlock organic and inorganic growth opportunities, including the capital-light infrastructure and new energy business, and deliver returns to shareholders in the future."

H1 2022 performance

·      Group net production averaged 49,726 Boepd (2021: 46,187 Boepd)

·      Revenue and other operating income of $943.5 million (2021: $518.3 million) and adjusted EBITDA of $536.3 million (2021: $345.4 million) reflects materially higher realised oil prices of $89.9/Boe (2021: $62.8/Boe), including the impacts of the Group's hedge programme, and higher production

·      Operating costs increased to $208.4 million (2021: $153.0 million), primarily reflecting the addition of Golden Eagle to the portfolio, increased maintenance and well intervention activity, and increased diesel and emissions trading certificate prices

·      Cash generated from operations was $522.7 million (2021: $287.9 million); with cash capital expenditure of $54.7 million (2021: $15.9 million) and cash abandonment expenditure of $28.2 million (2021: $38.7 million)

·      Strong free cash flow generation of $332.1 million (2021: $144.5 million)

End June net debt reduced by $342.0 million from year end; net debt to adjusted EBITDA reduced to 0.9x

·      At 30 June 2022, net debt reduced to $880.0 million (end 2021: $1,222.0 million) reflecting strong free cash flow generation. Group net debt to last-12 months adjusted EBITDA ratio as at 30 June 2022 is 0.9x, down from 1.6x at the end of 2021

·      At the end of June, $115.0 million remained outstanding on the Group's senior secured debt facility ('RBL') following accelerated repayments totalling $300.0 million

·      Completed partial refinancing and extended the maturity of the Sterling retail bond on 20 April, with the new October 2027 9% retail bond issue totalling £133.3 million. The remaining October 2023 7% retail bond in issue is £111.3 million

·      At the end of June, total cash and available facilities were $467.0 million (end 2021: $318.7 million)

·      At 31 August 2022, net debt had been further reduced to $817.6 million

·      The outstanding RBL was reduced to $90.0 million

·      Executed $33.4 million (4.0%) of buy backs of the October 2023 7% high yield bonds in July and August bringing the total outstanding at the end of August down to $793.8 million

Guidance and outlook

·      2022 average net Group production is expected to be within the guidance range of 44,000 Boepd and 51,000 Boepd reflecting strong first half performances across the portfolio and the impacts of the planned well programme and maintenance shutdowns in the second half of the year

·      Operating costs, cash capital and abandonment expenditures are all expected to be in line with prior guidance

·      EnQuest has hedged a total of c.3.4 MMbbls with an average floor of c.$60/bbl and ceiling price of c.$79/bbl in the second half of 2022. For the first half of 2023, the Group has hedged a total of c.3.5 MMbbls with an average floor price of c.$57/bbl and an average ceiling price of c.$77/bbl

·      Following the enactment of the Energy Profits Levy, EnQuest expects to pay cash tax in the UK in 2022 and for the duration of the levy period

 

Production and financial information

Business performance measures	For the period to 30 June 2022	For the period to 30 June 2021		Change %
Production (Boepd)	49,726	46,187		7.7
Revenue and other operating income ($m)1	943.5	518.3		82.0
Realised oil price ($/bbl)1,2	89.9	62.8		43.2
Average unit operating costs ($/Boe)2	22.7	19.3		17.6
Adjusted EBITDA ($m)2	536.3	345.4		55.3
Cash expenditures ($m)	82.9	54.6		51.8
Capital	54.7	15.9		244.0
Abandonment	28.2	38.7		(27.1)
Free cash flow ($m)2	332.1	144.5		129.8
	30 June 2022	31 December 2021
Net (debt)/cash ($m)2	(880.0)	(1,222.0)		(28.0)
Statutory measures	For the period to 30 June 2022	For the period to 30 June 2021		Change %
Reported revenue and other operating income ($m)3	838.8	481.3		74.3
Reported gross profit ($m)	252.8	148.1		70.7
Reported profit/(loss) after tax ($m)	203.5	(56.4)		-
Reported basic earnings/(loss) per share (cents)	11.1	(3.4)		-
Cash generated from operations ($m)	522.7	287.9		81.6
Net increase/(decrease) in cash and cash equivalents ($m)	99.5	53.3		86.7

 

 Notes:

¹ Including realised losses of $162.3 million (2021: realised losses of $32.9 million) associated with EnQuest's oil price hedges

² See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 31. Note, EnQuest defines net debt as excluding finance lease liabilities

³ Including net realised and unrealised losses of $267.0 million (2021: net realised and unrealised gains of $69.9 million) associated with EnQuest's oil price hedges

 

Summary financial review

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

Revenue for the six months ended 30 June 2022 was $943.5 million, 82.0% higher than the same period in 2021 ($518.3 million), reflecting the materially higher oil prices and the contribution of Golden Eagle. Revenue is predominantly derived from crude oil sales, which for the first half of 2022 totalled $851.2 million, 73.5% higher than in the same period of 2021 ($490.5 million). Revenue from the sale of condensate and gas in the period was $252.9 million (2021: $57.9 million), primarily reflecting higher market prices for condensate and gas. Gas revenue mainly relates to the onward sale of third-party gas purchases not required for injection activities at Magnus.

The Group's commodity hedges and other oil derivatives contributed $162.3 million of realised losses (2021: losses of $32.9 million), as a result of the timing at which the hedges were entered into. The Group's average realised oil price excluding the impact of hedging was $111.0/bbl for the six months ended 30 June 2022, compared to $67.3/bbl received during the first half of 2021. The Group's average realised oil price including the impact of hedging was $89.9/bbl in the first half of 2022, 43.2% higher than during the first half of 2021 ($62.8/bbl).

Total cost of sales were $585.6 million for the six months ended 30 June 2022, 75.7% higher than in same period of 2021 ($333.3 million).

Operating costs increased by $55.4 million to $208.4 million (2021: $153.0 million) primarily as a result of higher production costs reflecting the Golden Eagle acquisition in October 2021, higher maintenance and workover activities and the impact of higher market prices on diesel and emissions trading certificates. Unit operating costs increased by 17.6% to $22.7/Boe (2021: $19.3/Boe) reflecting higher costs partially offset by higher production.

Total cost of sales included non-cash depletion expense of $174.2 million, 13.8% higher than in the same period in 2021 ($153.1 million), mainly reflecting the impact of the Golden Eagle acquisition.

Also within cost of sales, the credit relating to the Group's lifting position and hydrocarbon inventory for the six months ended 30 June 2022 was $29.9 million (2021: credit of $26.1 million). The credit in the period reflects a switch to a $5.2 million net underlift position at 30 June 2022 from an $18.0 million net overlift position at 31 December 2021.

Other cost of sales, which forms part of the total cost of sales balance, of $232.9 million were higher than the same period in 2021 ($53.3 million), reflecting the higher cost of Magnus-related third-party gas purchases following the increase in the market price for gas which is offset by gas sales presented in revenue.

Adjusted EBITDA for the six months ended 30 June 2022 was $536.3 million, up 55.3% compared to the same period in 2021 ($345.4 million), driven by higher revenue.

The tax charge for the six months ended 30 June 2022 was $142.4 million (2021: $19.4 million tax credit). The tax charge in the period is largely non-cash and reflects the tax impact on the Group's increased profit before tax. Ring Fence Expenditure Supplement ('RFES') on UK activities, which would historically have provided an offset to the UK tax charge, ceased to be available to claim from the end of 2021. Had the Energy Profits Levy ('EPL') been enacted in the interim period, a cash tax liability of $5.6 million would have been recognised in respect of Business Performance in the period 26 May 2022 to 30 June 2022.

Remeasurements and exceptional items were a net post-tax profit of $23.5 million for the six months ended 30 June 2022 (2021: loss of $164.6 million). Revenue included unrealised losses of $104.7 million in respect of the mark-to-market movement on the Group's commodity contracts (2021: unrealised losses of $37.0 million). Other remeasurements and exceptional items includes a non-cash impairment reversal of $10.1 million (2021: nil) and a $31.0 million loss (2021: $27.5 million gain) in relation to the fair value recalculation of the Magnus contingent consideration reflecting a forecast increase in Magnus future cash flows, both as a result Group's increased short-term oil price forecast. A net tax credit of $163.4 million (2021: charge of $124.9 million) has been presented as exceptional, representing the non-cash recognition of $107.9 million of undiscounted deferred tax assets due to the Group's increased short-term oil price assumptions and the tax impact of the above items. Had the EPL been enacted in the interim period, a cash tax liability of $14.4 million would have been recognised in respect of Remeasurements and exceptional items in the period 26 May 2022 to 30 June 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 30 June 2022 were $2,627.7 million (2021: $3,011.0 million). 

The Group's reported net cash flow from operations for the six months ended 30 June 2022 was $498.4 million (2021: $246.9 million). Free cash flow for the six months ended 30 June 2022 was $332.1 million (2021: $144.5 million) reflecting the materially higher oil price resulting in higher cash receipts. Strong free cash flows enabled the Group to make early voluntary repayments totalling $300.0 million of the Reserve Based Lending (RBL) facility.

Net debt at 30 June 2022 was $880.0 million, a decrease of 28.0% compared to 31 December 2021 ($1,222.0 million) and includes $202.5 million of payment in kind interest ("PIK interest") that has been capitalised to the principal of the facility and bonds pursuant to the terms of the Group's November 2016 refinancing (31 December 2021: $225.0 million). As at 31 August 2022, net debt had been further reduced to $817.6 million.

 

Operating review

 

Production details

Average daily production on a net working interest basis		For the period to 30 June 2022	For the period to 30 June 2021
		(Boepd)	(Boepd)
UK Upstream
- Magnus		12,754	13,847
- Kraken		19,527	23,690
- Golden Eagle1		7,060	-
- Other Upstream2		4,081	3,504
UK Upstream		43,422	41,041
UK Decommissioning3		-	337
Total UK		43,422	41,378
Total Malaysia		6,304	4,809
Total EnQuest		49,726	46,187

 

¹ Golden Eagle acquisition completion date was 22 October 2021

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

³ UK Decommissioning: the Dons

 

Upstream operations

UK operations

Magnus

Average production for the first six months of 2022 was 12,754 Boepd, 7.9% lower than the first half of 2021. Production was impacted by a seawater lift pump failure and a well integrity failure in June. The pump was replaced in July with additional spares purchased to mitigate potential future risks. The Group's well intervention programme is ongoing, with two wells successfully returned to service in the first half of 2022. The North West Magnus production well, which is the longest reservoir section drilled this century at 1,914 metres with the longest liner ever run at Magnus, has been successfully drilled and logged in late July and is expected online around the end of September. The programme in the second half of the year continues to evolve as EnQuest focuses on the most value-accretive opportunities, resulting in the Group prioritising a number of interventions to mitigate well failure risk and the return to service of the June well failure. Further infill drilling is now expected in 2023.

 

The planned three-week maintenance shutdown is underway, with production expected to resume later this month.

 

Kraken

Average production of 19,527 Boepd (27,698 Boepd gross) (2021: 23,690 Boepd net; 33,603 Boepd gross) is above the top end of the Group's 2022 guidance. The floating production, storage and offloading vessel ('FPSO') delivered top quartile performance, with production efficiency of 92% and water injection efficiency of 95%, with the reduction in production from 2021 reflecting the impact of natural decline. The Group has optimised its planned third-quarter maintenance activities, which are scheduled to start in early September, allowing Kraken to continue to operate on a single processing train for one week of the two-week programme duration. Dual-train operations are expected to resume later in September.

 

Near-field drilling and subsea tie-back opportunities are being assessed. Following completion of a 3D seismic campaign in 2021, work is ongoing to interpret the seismic data in order 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. The current expectation is the execution of an initial side-track opportunity in 2024, before future drilling of wells in the western area. Equipment orders are likely to be placed during 2022 in order to accommodate significant supply chain lead times.

 

Golden Eagle

Year to date June production was 7,060 Boepd. Production efficiency remained strong at 95%, including an optimised annual shutdown which was executed in two days instead of four, partially offset by plant instability caused by gas turbine trips and natural decline. These issues are being addressed by the operator, with further optimisation activities, including well work, planned in the second half of the year.

 

The joint venture has approved a two infill well drilling campaign to commence at the end of the third quarter of 2022, with first oil expected around the end of the first quarter of 2023. EnQuest is proactively working with the operator to share insights to optimise drilling performance and future well work.

 

Other Upstream assets

Production for the first six months of 2022 averaged 4,081 Boepd (2021: 3,504 Boepd). This was driven by uptime of 92% at the Greater Kittiwake Area ('GKA'), and the continued positive impact of work completed in the first quarter to optimise gas lift delivery pressure. The planned 11-day GKA shutdown was completed three days ahead of schedule, with the asset back online in August. EnQuest has also implemented a gas accumulator to mitigate the need for import gas to support GKA's re-start requirements.

 

Alba continues to perform in line with Group expectations.

 

EnQuest is working with its partners to progress field development studies for Bressay and the Bentley team is focused on re-evaluation of the existing subsurface data.

 

Malaysia operations

For the first six months of 2022, average production in Malaysia was 6,304 Boepd, representing a 31% increase over the same period last year. This increase was driven by the riser pipeline replacement during the first quarter of 2022 and completion of three out of the four planned workovers. The fourth workover was completed in July. In aggregate, the workover programme was delivered on budget and ahead of schedule with production in line with expectations. The Group has also successfully executed a three-well plug and abandonment ('P&A') campaign at PM8/Seligi. In recognition of this workover and P&A performance, EnQuest received three Petronas Recognition Awards centred on a commitment to safety, application of new technology to leverage efficiencies in schedule and cost savings.

 

Following the mobilisation and installation of the drilling rig at the Seligi-C satellite platform, and the drilling of a pilot hole during June, the infill drilling campaign has commenced with the Group's first horizontal well at PM8/Seligi being brought on stream in July, with higher than expected initial production rates. The drilling rig subsequently mobilised to the Seligi-D satellite platform, where two more horizontal wells are expected to be delivered in 2022.

 

Looking ahead, the Group has sanctioned a three well infill drilling programme in 2023, in alignment with the established asset strategy.

 

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, and a proposed exploration well has been identified. The Group has a commitment to drill the exploration well by the end of the PM409 exploration period, which ends in December 2023.

 

Decommissioning

Heather and Thistle P&A campaigns are progressing well with six wells completed at Heather and nine wells completed at Thistle. The Group continues to demonstrate and develop capability in delivering these significant decommissioning projects and remains on track to complete the P&A of 16 wells at each installation in 2022.

 

The tender processes for heavy lift vessels for Heather and Thistle topsides and jacket removals has concluded. Contracts to complete those scopes, which have scheduled windows between 2024 and 2026, are expected to be awarded in the second half of 2022. The Group is aware of increased competition in the heavy lift vessel market, with the evolution of several large-scale renewable projects being sanctioned by the governments of European countries, and has moved to manage execution of heavy lift scopes within multi-year windows in order to retain flexibility and mitigate availability concerns.

 

At the Dons, subsea infrastructure removal within the 500-metre zone is progressing as expected, with two phases completed during the first half of the year, and the final phase scheduled for completion in September. The North Sea Transition Authority ('NSTA') recently recognised the floating production facility off station project as an example of exemplary execution and best-in-class performance in the North Sea for prompt asset removal, reduction of post-cessation of production operating expense and CO₂ reduction.

 

The EnQuest Producer FPSO remains in warm stack at Nigg Energy Park while the Group continues to evaluate options, which include utilisation on a future project or sale.

 

Infrastructure and New Energy

The Sullom Voe Terminal ('SVT') and its related infrastructure maintained safe and reliable performance, with 100% export service availability during the first half of 2022.

 

EnQuest continues to develop cost-effective and efficient plans to transform the terminal and prepare and repurpose the site to progress decarbonisation opportunities at scale, focused on carbon capture and storage ('CCS'), electrification and green hydrogen. The terminal site offers several unique competitive advantages, including a 1,000-acre industrial site with access to existing oil and gas pipeline infrastructure, a deep-water port and jetties, the highest wind capacity factor across Europe, and a highly skilled workforce and local supply chain. In advancing its Infrastructure and New Energy business, the Group will maintain its focus on capital discipline and, having secured exclusivity from the Shetland Islands Council to progress new energy opportunities on the site to achieve value for the Council, the Shetland community and EnQuest, the Group is well placed to deliver on its new energy ambitions alongside strategic delivery partners.

 

Carbon Capture and Storage

The availability of the deep-water port and jetties and a pipeline network linked to several well-understood offshore reservoirs presents the opportunity to repurpose infrastructure to import and permanently store material quantities of CO₂ from isolated emitters in the UK, Europe or further afield.

 

EnQuest has conducted initial phases of feasibility and economic screening work in respect of this carbon storage concept. These studies have indicated the capability of the existing infrastructure, including the EnQuest operated East of Shetland pipeline system, and storage sites to support a project of up to 10 million tonnes per annum of CO₂. In May 2022, the Group made two CCS licence area nominations in locations which are both accessible from EnQuest's existing infrastructure. These were both accepted and EnQuest expects to make two applications in respect of these licence areas in the forthcoming NSTA UK offshore CCS licensing round, with results expected to be announced in the first quarter of 2023.

 

Electrification

EnQuest is assessing the potential to leverage its existing infrastructure and subsea projects expertise to facilitate the electrification of nearby offshore oil and gas assets and planned developments by way of a grid connection supplemented with renewable power. This would lead to significant emissions reductions for platforms which are expected to operate into the 2050's. In addition, the Group is also currently assessing onshore wind potential and a new power solution for the Sullom Voe Terminal, which has the potential to significantly reduce the Group's carbon footprint.

 

Green Hydrogen

The Group is exploring the potential for repurposing areas of the existing SVT site and harnessing the advantaged natural wind resource around Shetland for the production of green hydrogen and derivatives at export scale to provide a low carbon alternative fuel which could help to decarbonise a number of industries. 

 

Liquidity and net debt

The Group generated strong free cash flows during the first half of 2022, resulting in net debt of $880.0 million at 30 June 2022, down $342.0 million since the end of 2021. This reduction was driven by accelerated repayments totalling $300.0 million on the Group's RBL facility, with drawings of $115.0 million at 30 June 2022, significantly ahead of the required amortisation schedule. EnQuest's 12-month net debt to adjusted EBITDA ratio at 30 June 2022 was 0.9x and the Group had total cash and available facilities of $467.0 million, including restricted funds and ring-fenced funds held in joint venture operational accounts totalling $286.1 million (31 December 2021: $318.7 million and $191.4 million, respectively).

 

In line with EnQuest's continued focus on deleveraging, the Group has further reduced its net debt to $817.6 million at the end of August. The outstanding RBL facility was reduced to $90.0 million and the Group bought back and cancelled $33.4 million of its 2023 7% high yield bonds across July and August, leaving $793.8 million outstanding. The Group may, from time to time, purchase its outstanding notes in open-market purchases and/or privately negotiated transactions and upon such terms and at such prices as it may determine. The Group will evaluate any such transactions in light of then-existing market conditions, taking into account the Group's current liquidity and prospects for future access to capital. The amounts involved in any such transactions, individually or in the aggregate, may be material. At the same time, the Group continues to explore options to refinance its high yield bond ahead of maturity in October 2023.

 

2022 outlook           

The Group remains on track to achieve net production between 44,000 and 51,000 Boepd, with a significant well work and drilling campaigns progressing across the portfolio, partially offset by natural declines and planned maintenance shutdowns at Magnus and Kraken in the third quarter.

 

Full year expectations for operating, cash capital and abandonment expenditures remain unchanged from the Group's original guidance at approximately $430 million, $165 million and $75 million, respectively, with capital and abandonment spend in particular expected to be higher during the second half of the year, in line with activity. EnQuest remains focused on cost discipline and has been proactive in engagement with its global supply chain to mitigate the impacts of cost inflation within the current year.

 

Following the enactment of the EPL, EnQuest expects to pay cash tax in the UK in 2022 and for the duration of the levy period. The first payment on account under the EPL will be paid in December 2022. EnQuest remains committed to investment in the North Sea and is reviewing future capital expenditure programmes in light of the additional investment allowances available under the levy.

 

EnQuest hedged a total of c.8.7 MMbbls for 2022 predominantly using costless collars, with an average floor price of c.$63/bbl and an average ceiling price of c.$77/bbl. For the period July to December 2022, c.3.4 MMbbls of production remains hedged with an average floor price of c.$60/bbl and an average ceiling price of c.$79/bbl.

 

Environmental, Social and Governance

The health, safety and wellbeing of EnQuest's people is its top priority and the Group has continued to perform well in this regard in the six months to end June, recording a Lost Time Incident ('LTI') frequency¹ of zero (Full year 2021: 0.21). However, during August the Group saw its first LTI in 10 months. EnQuest has a strong safety culture and will remain focused on continuous improvement to prevent personal injuries, dangerous occurrences and hydrocarbon releases.

 

In line with EnQuest's purpose of delivering creative solutions through the energy transition and society's need for fossil fuels to meet today's energy demand while moving towards lower carbon energy in the future, the Group is engaged across the energy spectrum. Managing existing assets in a responsible and sustainable manner is a key part of the energy transition. EnQuest has a disciplined strategy of acquiring existing hydrocarbon assets, safely driving production and cost efficiencies, maturing additional reserves and extending asset lives through focused maintenance and enhancement programmes and identifying repurposing opportunities. This strategy supports security of energy supply and helps to maximise economic recovery of those assets.

 

Emissions reductions are clearly a core focus area for the Group and EnQuest is committed to playing its part in the achievement of national emissions reduction targets and the drive to 'net-zero', with the Infrastructure and New Energy business having overall responsibility for delivering the Group's emission reduction objectives. Since 2018, UK Scope 1 and 2 emissions

 

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)

have reduced by more than 40%, which is significantly ahead of the UK Government's North Sea Transition Deal target of achieving a 10% reduction in Scope 1 and 2 CO₂ equivalent emissions by 2025 and is close to the 50% reduction targeted by 2030.

 

Corporate governance is an essential part of EnQuest's governance framework, supporting both risk management and the Group's core Values. The Board remains focused on Board and executive succession planning. In January 2022, Rani Koya joined the EnQuest Board, bringing extensive industry and renewable energy experience. As part of the Group's planned rotation of Directors, Philip Holland stepped down from the Board of Directors and as Chair of the Safety, Climate and Risk Committee following the Group's AGM in June, with Liv Monica Stubholt assuming the role of Chair. Following Philip's departure, EnQuest's Board diversity is in line with the original Hampton-Alexander recommendations. Also in June, Martin Houston notified the Board of his intention to step down as Non-Executive Chairman to focus on his other business interests. The search process for Martin's successor is underway and is being led by the Group's Senior Independent Director, Howard Paver. In August, Salman Malik, previously the Group's Managing Director - Corporate Development, Infrastructure and New Energy and a member of the Group's Executive Committee, joined the Board as Chief Financial Officer, replacing Jonathan Swinney who informed the Board of his intention to step down in March 2022.

 

- Ends -

For further information, please contact:

 

EnQuest PLC	Tel: +44 (0)20 7925 4900
Amjad Bseisu (Chief Executive)
Salman Malik (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 10.30 today - London time. The presentation will be accessible via a webcast by clicking here. A conference call facility will also be available at 10.30am and dial-in details can be found by clicking here.

 

Notes to editors

This announcement has been determined to contain inside information. The person responsible for the release of this announcement is Paul Massie, General Counsel Delegation of Authority and Interim Company Secretary.

ENQUEST

EnQuest is providing creative solutions through the energy transition. As an independent energy company with operations in the UK North Sea and Malaysia, the Group aims to responsibly optimise production, leverage existing infrastructure, deliver a strong decommissioning performance and explore new energy and further decarbonisation opportunities by focusing on operational excellence, differential capability, value enhancement and financial discipline.

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

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

 

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

Financial review

Financial overview

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

 

Production on a working interest basis increased by 7.7% to 49,726 Boepd, compared to 46,187 Boepd in 2021.

Revenue for the six months ended 30 June 2022 was $943.5 million, 82.0% higher than the same period in 2021 ($518.3 million), reflecting the materially higher oil prices and the contribution of Golden Eagle. The Group's commodity hedge programme, predominantly entered into during the second half of 2021, resulted in realised losses of $162.3 million in the first half of 2022 (2021: losses of $32.9 million).

The Group's operating costs of $208.4 million were 36.1% higher than in the same period in 2021 ($153.0 million). This increase primarily reflects the addition of Golden Eagle to the portfolio, well intervention work at Magnus and PM8/Seligi, additional maintenance spend at Magnus and higher diesel and emissions credit prices. Unit costs increased to $22.7/Boe (2021: $19.3/Boe), primarily reflecting higher costs partially offset by higher production.

Other cost of sales, which forms part of the total cost of sales balance, for the six months ended 30 June 2022 of $232.9 million were 337.0% higher than the same period in 2021 ($53.3 million), principally as a result of higher Magnus-related third-party gas purchases reflecting the increase in associated market prices and which is offset by higher gas sales, presented within revenue. The average day ahead gas price increased from 52p/Therm for the six months ended 30 June 2021 to 182p/Therm for the six months ended 30 June 2022.

Adjusted EBITDA for the six months ended 30 June 2022 was $536.3 million, up 55.3% compared to the same period in 2021 ($345.4 million), driven by higher revenue.

	H1 2022 $ million	H1 2021  $ million
Profit/(loss) from operations before tax and finance income/(costs)	416.2	175.4
Depletion and depreciation	177.5	157.0
Change in provision	(32.3)	5.7
Change in well inventories	(0.4)	1.0
Net foreign exchange (gain)/loss	(24.7)	6.3
Adjusted EBITDA	536.3	345.4

 

EnQuest's net debt decreased by $342.0 million to $880.0 million at 30 June 2022 (31 December 2021: $1,222.0 million) as a result of strong free cash flow generation of $332.1 million. Net debt includes $202.5 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 2021: $225.0 million).

	Net debt/(cash)1
	30 June  2022 $ million	31 December 2021 $ million
Bonds	1,126.4	1,083.8
Senior secured debt facility ('RBL')	115.0	415.0
SVT Working Capital Facility	8.3	9.9
Cash and cash equivalents	(369.7)	(286.7)
Net debt	880.0	1,222.0

 

Note:

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

 

The Group's strong free cash flow generation during the first half of 2022 enabled the Group to make early voluntary repayments of the RBL totalling $300.0 million, well ahead of the required amortisation schedule. As at the end of August, the Group had further reduced the amount outstanding under the RBL to $90.0 million.

 

During the period, the Group also successfully refinanced its 7% Sterling Retail Bond ('7% Retail Bond') through an exchange and open offer which concluded on 27 April 2022. The principal of the new 9% Sterling Retail Bond ('9% Retail Bond') raised was £133.3 million, made up of £79.3 million of exchanges from the 7% Retail Bond and £54.0 million from new bond holders.

 

In July and August, the Group bought back and cancelled $33.4 million of its 2023 7% high yield bonds, leaving $793.8 million outstanding.

 

The Group continues to have unrestricted access to its UK North Sea corporate tax losses, subject only to generating suitable future profits, which at 30 June 2022 were $2,627.7 million (2021: $3,011.0 million). In the current environment, no significant corporation tax or supplementary charge is expected to be paid on UK operational activities for the foreseeable future, although had the Energy Profits Levy ('EPL') been considered in the interim period, a cash tax liability of $20.0 million would be recognised of which $5.6 million would have been in respect of the Business Performance in the period 26 May 2022 to 30 June 2022. The Group paid cash corporate income tax on the Malaysian assets, which will continue throughout the life of the production sharing contract.

Income statement

Revenue

On average, market prices for crude oil in the first half of 2022 were significantly higher than in the same period of 2021. The Group's average realised oil price excluding the impact of hedging was $111.0/bbl for the six months ended 30 June 2022, compared to $67.3/bbl received during the first half of 2021. Revenue is predominantly derived from crude oil sales, which for the first half of 2022 totalled $851.2 million, 75.3% higher than in the same period of 2021 ($490.5 million), reflecting the materially higher oil prices and the contribution of Golden Eagle. Revenue from the sale of condensate and gas in the period was $252.9 million (2021: $57.9 million), primarily reflecting higher market prices. Gas revenue mainly relates to the onward sale of third-party gas purchases not required for injection activities at Magnus. Tariffs and other income generated $1.7 million (2021: $2.8 million). The Group's commodity hedges and other oil derivatives contributed $162.3 million of realised losses (2021: losses of $32.9 million), as a result of the timing at which the hedges were entered into. The Group's average realised oil price including the impact of hedging was $89.9/bbl in the first half of 2022, 43.2% higher than during the first half of 2021 ($62.8/bbl).

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

 

Cost of sales¹

	H1 2022 $ million	H1 2021 $ million
Production costs	181.2	139.5
Tariff and transportation expenses	23.4	21.7
Realised loss/(gain) on derivatives related to operating costs	3.8	(8.2)
Operating costs	208.4	153.0
(Credit)/charge relating to the Group's lifting position and hydrocarbon inventory	(29.9)	(26.1)
Depletion of oil and gas assets	174.2	153.1
Other cost of sales	232.9	53.3
Cost of sales	585.6	333.3
Unit operating cost2	$/Boe	$/Boe
- Production costs	20.1	16.7
- Tariff and transportation expenses	2.6	2.6
Average unit operating cost	22.7	19.3

 

Notes:

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

2 Calculated on a working interest basis

 

Cost of sales were $585.6 million for the six months ended 30 June 2022, 75.7% higher than in same period of 2021 ($333.3 million).

Operating costs increased by $55.4 million, primarily reflecting higher production costs for the first half of 2022. This increase was driven by the addition of Golden Eagle to the portfolio, well intervention work at Magnus and PM8/Seligi, maintenance spend at Magnus and higher diesel and emissions credit prices. Unit operating costs increased by 17.6% to $22.7/Boe (2021: $19.3/Boe) primarily reflecting higher costs partially offset by higher production.

The credit relating to the Group's lifting position and hydrocarbon inventory for the six months ended 30 June 2022 was $29.9 million (2021: credit of $26.1 million). The credit in the period primarily reflects a switch to a $5.2 million net underlift position at 30 June 2022 from a $18.0 million net overlift position at 31 December 2021. This was primarily driven by the unwind of the overlift at Magnus from year end.

Depletion expense of $174.2 million was 13.8% higher than in the same period in 2021 ($153.1 million), mainly reflecting the addition of Golden Eagle to the portfolio.

Other cost of sales, which forms part of the total cost of sales balance, for the six months ended 30 June 2022 of $232.9 million were higher than the same period in 2021 ($53.3 million), reflecting the higher cost of Magnus-related third-party gas purchases following the increase in the market price for gas which is offset by gas sales presented in revenue.

Other income and expenses

Net other income of $61.3 million (2021: net other expense of $9.5 million) is primarily due to $32.3 million change in decommission estimate of fully impaired assets (including the Thistle linked decommissioning liability, see note 11) and $24.7 million of net foreign exchange gains. 2021 primarily reflected the recognition of $6.3 million expenses in relation to the increase in the decommissioning provision of fully impaired assets and foreign exchange losses of $6.4 million, partially offset by other income.

Finance costs

Finance costs of $94.1 million were 8.7% higher than in the comparative period (2021: $86.6 million). This increase was primarily driven by a $14.2 million increase in amortisation of finance fees associated with the Group's loans and bonds (2022: $17.9 million; 2021: $3.7 million) reflecting accelerated RBL repayments, partially offset by a $6.0 million decrease in bond interest payable (2022: $31.5 million; 2021: $37.5 million). Other finance costs included loan interest payable of $8.6 million (2021: $10.8 million), $8.9 million on unwinding of discount on decommissioning provisions and other liabilities (2021: $8.5 million) and other financial expenses of $3.4 million (2021: $2.6 million), primarily being the cost for surety bonds to provide security for decommissioning liabilities.

Taxation

The tax charge for the six months ended 30 June 2022 of $142.4 million (2021: $19.4 million tax credit), excluding exceptional items. The tax charge in the period is largely non-cash and reflects the tax impact on the Group's increased profit before tax. Ring Fence Expenditure Supplement ('RFES') on UK activities, which would historically have provided an offset to the UK tax charge, ceased to be available to claim from the end of 2021. Had the Energy Profits Levy ('EPL') been enacted in the interim period, a cash tax liability of $5.6 million would have been recognised in respect of Business Performance in the period 26 May 2022 to 30 June 2022.

Remeasurements and exceptional items

Remeasurements and exceptional items resulting in a post-tax net profit of $23.5 million have been disclosed separately for the six month period ended 30 June 2022 (2021: loss of $164.6 million).

Revenue included unrealised losses of $104.7 million in respect of the mark-to-market movement on the Group's commodity contracts (2021: unrealised losses of $37.0 million).

A net impairment reversal of $10.1 million has been disclosed in remeasurements (2021: nil). The increase in EnQuest's near-term future oil price assumptions were largely offset by the increase in discount rate from 10% to 11% and the impact of tax, including the recently introduced UK EPL.

Other expense included a $31.0 million loss in relation to the fair value recalculation of the Magnus contingent consideration reflecting a forecast increase in Magnus future cash flows as a result Group's increased short-term oil price forecast (2021: $27.5 million gain). Other finance costs mainly relate to the unwinding of contingent consideration from the acquisition of Magnus and associated infrastructure of $17.9 million (2021: $30.3 million).

A net tax credit of $163.4 million (2021: charge of $124.9 million) has been presented as exceptional, representing the non-cash recognition of $107.9 million of undiscounted deferred tax assets due to the Group's increased short-term oil price assumptions and the tax impact of the above items. Had the EPL been enacted in the interim period, a cash tax liability of $14.4 million would have been recognised in respect of Remeasurements and exceptional items in the period 26 May 2022 to 30 June 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 30 June 2022 were $2,627.7 million (2021: $3,011.0 million). 

IFRS results

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

EnQuest IFRS revenue reflects the Group's Business performance revenue, 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 any 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 $294.2 million (2021: profit of $165.9 million), IFRS profit before tax was $182.6 million (2021: profit of $49.1 million), and IFRS profit after tax was $203.5 million (2021: loss of $56.4 million).

Earnings per share

The Group's Business performance basic profit per share was 9.8 cents (2021 profit per share: 6.6 cents) and diluted profit per share was 9.6 cents (2021 profit per share: 6.5 cents).

The Group's reported basic profit per share was 11.1 cents (2021 loss per share: 3.4 cents) and reported diluted profit per share was 10.9 cents (2021 loss per share: 3.4 cents).

Cash flow and liquidity

Net debt at 30 June 2022 amounted to $880.0 million, including PIK of $202.5 million, compared with net debt of $1,222.0 million at 31 December 2021, including PIK of $225.0 million. The movement in net debt was as follows:

	$ million
Net debt 1 January 2022	1,222.0
Net cash flows from operating activities	498.4
Cash capital expenditure	(54.7)
Net interest and finance costs paid	(52.3)
Finance lease payments	(59.3)
Other movements, primarily net foreign exchange on cash and debt	9.9
Net debt 30 June 20221	880.0

 

Note:

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

 

The Group's reported net cash flows from operating activities for the six month period ended 30 June 2022 were $498.4 million, up 101.8% compared to comparative period of 2021 ($246.9 million), primarily driven by materially higher revenue.

 

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

	H1 2022 $ million	H1 2021 $ million
North Sea	43.7	11.0
Malaysia	8.9	3.9
Exploration and evaluation	2.1	1.0
	54.7	15.9

 

Cash capital expenditure in the period ended 30 June 2022 primarily related to Magnus and PM8/Seligi well campaigns. Cash capital expenditure in 2021 primarily related to Magnus well interventions and the PM8/Seligi pipeline replacement projects.

Balance sheet

 

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

PP&E has decreased by $149.1 million to $2,672.9 million at 30 June 2022 from $2,822.0 million at 31 December 2021 (see note 7). This decrease encompasses capital additions to PP&E of $55.1 million and net impairment reversal of $10.1 million, more than offset by depletion and depreciation charges of $177.5 million and a decrease in decommissioning estimate of $35.3 million.

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

	1H 2022 $ million	H1 2021 $ million
North Sea	42.0	20.8
Malaysia	13.1	7.2
	55.1	28.0

 

Trade and other receivables

Trade and other receivables increased by $15.3 million to $311.4 million at 30 June 2022 compared with $296.1 million at 31 December 2021. The increase is driven by the timing and pricing of cargo settlements.

Cash and net debt

The Group had $369.7 million of cash and cash equivalents at 30 June 2022 and $880.0 million of net debt, including PIK and capitalised interest of $202.5 million (2021: $286.7 million, $1,222.0 million and $225.0 million, respectively).

 

Net debt comprises the following liabilities:

·      $136.1 million principal outstanding on the Sterling 7% retail bond, including interest capitalised as PIK of $25.4 million (2021: $256.2 million and $47.9 million, respectively);

·      $163.1 million principal outstanding on the Sterling 9% retail bond;

·      $827.2 million principal outstanding on the high yield bond, including interest capitalised as PIK of $ 177.2 million (2021: $827.2 million and $177.2 million, respectively);

·      $115.0 million drawn down on the RBL (2021: $415.0 million); and

·      $8.4 million relating to the SVT Working Capital Facility (2021: $9.9 million).

 

Provisions

The Group's decommissioning provision decreased by $71.0 million to $764.7 million at 30 June 2022 (2021: $835.7 million), primarily reflecting a favourable foreign exchange rate movement and the ongoing decommissioning programmes at Heather and the Dons.

Other provisions, including the Thistle decommissioning provision, decreased by $10.2 million in the period to 30 June 2022 to $49.0 million (2021: $59.2 million). The Thistle decommissioning provision of $33.8 million (2020: $43.9 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 increased by $44.8 million. In the period to 30 June 2022, EnQuest paid nil to BP (2021: $1.0 million) under the profit sharing mechanism, reflecting the unwind of the early vendor loan repayment in 2021 and timing of cargos in 2022. A change in fair value charge of $26.9 million was recognised in the period (2021: $27.5 million) together with finance costs of $17.9 million (2021: $30.3 million).

 

The contingent consideration payable associated with the acquisition of Golden Eagle increased from $45.2 million at 31 December 2021 to $46.7 million at 30 June 2022.

Income tax

The Group had a net income tax payable of $12.0 million (2021: $3.6 million payable) primarily related to taxable income in Malaysia.

Deferred tax

The Group's net deferred tax asset has increased from $699.6 million at 31 December 2021 to $732.1 million at 30 June 2022. This is driven by higher short-term oil price assumptions. Had the EPL been fully enacted before 30 June 2022, these half-year results would have recognised an additional net deferred tax liability of $106.6 million at the period end.

EnQuest continues to have unrestricted access to its UK corporate tax losses carried forward at 30 June 2022 amounting to $2,627.7 million (31 December 2021: $3,011.0 million), subject only to generating suitable future profits.

Trade and other payables

Trade and other payables of $400.3 million at 30 June 2022 are $20.2 million lower than at 31 December 2021 ($420.5 million). The full balance is payable within one year.

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 Group's 2021 Annual report.

Going concern disclosure

The Group has generated strong cash flows in the first half of 2022 and materially reduced its net debt through the repayment of its RBL significantly ahead of the required amortisation schedule, as outlined below. The Group continues to closely monitor and manage its funding and liquidity position, 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 the Group to manage liquidity.

In 2021, EnQuest entered into a new RBL of $600.0 million and an additional amount of $150.0 million for letters of credit for up to seven years. 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. 

Strong free cash flow in the first six months of the year allowed the Group to repay $300.0 million of the RBL, with the available and outstanding RBL facility at $115.0 million at 30 June 2022, significantly ahead of the amortisation schedule. As at the end of August, the Group had further reduced the amount outstanding under the RBL to $90.0 million. 

On 20 April 2022, the Group completed an exchange and cash offer to partially refinance its October 2023 7% GBP retail bond with an October 2027 9% GBP retail bond. The 9% retail bond attracted £54.0 million through the cash offer and £79.3 million through the exchange offer, which together resulted in a principal issue of £133.3 million. The exchange offer has resulted in £111.3 million of the October 2023 7% retail bond remaining in issue.

The Group continues to explore options to refinance its high yield bond ahead of maturity in October 2023. As at 31 August 2022, $793.8 million remained outstanding following buy back and cancellation of $33.4 million of the bonds in July and August. For the purposes of assessing going concern, it is assumed that the refinancing of the remaining high yield bond and the settlement of the remaining 7% retail bond will occur outside of the going concern period in line with their maturities in October 2023.

The Group's latest assessment of the 2022 and 2023 forecast underpins management's base case ('Base Case') and uses oil price assumptions of $100.0/bbl from July to December 2022 and $90.0/bbl for 2023, adjusted for hedging activity undertaken by the Group. These oil prices are broadly in line with current consensus.

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

·      10.0% discount to Base Case prices resulting in Downside Case prices of $90.0/bbl from July to December 2022 and $81.0/bbl for 2023;

·      Production risking of 5.0% for the remainder of 2022 and for 2023; and

·      A 5.0% increase to operating and capital costs for 2023.

The Base Case and Downside Case indicate that the Group is able to operate as a going concern and remain covenant compliant for 12 months from the date of publication of this interim report. Having already part refinanced the retail bond, initiated buy back and cancellations of the high yield bond and following discussions with several financiers, the Directors are confident the Group will be able to refinance the high yield bond and generate sufficient cash flow to repay the outstanding amount due on the retail bond as they fall due under both the Base case and Downside Case assumptions. However, the Group may conclude a refinancing within the next 12 months to increase the maturity of its debt, and therefore further support the going concern assessment.

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

After making appropriate enquiries and assessing the progress against the forecast, projections, the Directors have a reasonable expectation that the Group will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing these financial statements.

 

 

Risks and uncertainties

The Group's risks and uncertainties were set out in the Annual Report and Accounts 2021 which was published in March 2022. Following the enactment of the Energy Profits Levy by the UK Government, the fiscal risk and government take risk and uncertainty likelihood has increased when compared to that which was disclosed in the Group's Annual Report and Accounts 2021. All of the Group's other risks and uncertainties remain unchanged from those published in March 2022.

 

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

 

Principal risks and uncertainties

 

·      Health, Safety and Environment ('HSE')

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

·      Oil and gas prices

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

·      Production

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

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

·      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.

·      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 its outstanding bonds which mature in October 2023. Further information is contained in the Financial review, particularly within the going concern disclosure on page 12.

·      Competition

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

·      IT security and resilience

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

·      Portfolio concentration

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

·      Subsurface risk and reserves replacement

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

·      Project execution and delivery

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

 

·      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. The implementation of the UK Government's EPL is expected to affect EnQuest's cash flow for the period in which the levy is applied.

·      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.

·      Joint venture partners

·      Failure by joint venture parties to fund their obligations.

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

·      Reputation

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

·      Human resources

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

 

 

Group Income Statement

For the six months ended 30 June 2022

		2022			2021
	Notes	Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in period $'000	Business performance $'000	Remeasurements and exceptional items (note 4) $'000	Reported in period $'000
		Unaudited	Unaudited	Unaudited	Unaudited	Unaudited	Unaudited
Revenue and other operating income	5	943,507	(104,672)	838,835	518,287	(36,973)	481,314
Cost of sales		(585,601)	(481)	(586,082)	(333,262)	-	(333,262)
Gross profit/(loss)		357,906	(105,153)	252,753	185,025	(36,973)	148,052
Net impairment reversal		-	10,122	10,122	-	-	-
General and administration expenses		(3,063)	-	(3,063)	(130)	-	(130)
Other income		62,300	4,061	66,361	4,333	27,490	31,823
Other expenses		(1,019)	(30,996)	(32,015)	(13,873)	-	(13,873)
Profit/(loss) from operations before tax and finance income/(costs)		416,124	(121,966)	294,158	175,355	(9,483)	165,872
Finance costs		(94,107)	(17,870)	(111,977)	(86,603)	(30,299)	(116,902)
Finance income		391	-	391	102	-	102
Profit/(loss) before tax		322,408	(139,836)	182,572	88,854	(39,782)	49,072
Income tax		(142,382)	163,353	20,971	19,411	(124,855)	(105,444)
Profit/(loss) for the year attributable to owners of the parent		180,026	23,517	203,543	108,265	(164,637)	(56,372)
Total comprehensive profit/(loss) for the period, attributable to owners of the parent				203,543			(56,372)

 

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

 

Earnings per share	6	$	$	$	$
Basic		0.098	0.111	0.066	(0.034)
Diluted		0.096	0.109	0.065	(0.034)

 

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

 

Group Balance Sheet

At 30 June 2022

 

	Notes	30 June  2022 $'000	31 December 2021 $'000
		Unaudited	Audited
ASSETS
Non-current assets
Property, plant and equipment	7	2,672,877	2,821,998
Goodwill		134,400	134,400
Intangible oil and gas assets		40,193	47,667
Deferred tax assets		735,049	702,970
Other long term assets	9	6	6
		3,582,525	3,707,041
Current assets
Inventories		90,110	73,023
Trade and other receivables		311,373	296,068
Current tax receivable		2,050	2,368
Cash and cash equivalents		369,720	286,661
Other financial assets	9	1,203	472
		774,456	658,592
TOTAL ASSETS		4,356,981	4,365,633
EQUITY AND LIABILITIES
Equity
Share capital and premium		392,196	392,196
Share-based payment reserve		8,859	6,791
Retained earnings		325,312	121,769
TOTAL EQUITY		726,367	520,756
Non-current liabilities
Borrowings	8	50,000	191,109
Bonds	8	1,125,069	1,081,596
Lease liabilities		403,171	442,500
Contingent consideration	10	402,433	380,301
Provisions	11	730,821	754,266
Deferred tax liabilities		2,932	3,418
		2,714,426	2,853,190
Current liabilities
Borrowings	8	65,676	210,505
Lease liabilities		136,874	128,281
Contingent consideration	10	54,704	30,477
Provisions	11	82,842	140,676
Trade and other payables		400,298	420,544
Other financial liabilities	9	161,789	55,247
Current tax payable		14,005	5,957
		916,188	991,687
TOTAL LIABILITIES		3,630,614	3,844,877
TOTAL EQUITY AND LIABILITIES		4,356,981	4,365,633

 

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

 

 

Group Statement of Changes in Equity

For the six months ended 30 June 2022

	Share capital and share premium $'000	Share-based payments reserve $'000	Retained earnings $'000	Total $'000
	Unaudited	Unaudited	Unaudited	Unaudited
Balance at 1 January 2021	345,420	1,016	(255,219)	91,217
Profit/(loss) for the period	-	-	(56,372)	(56,372)
Total comprehensive loss for the period	-	-	(56,372)	(56,372)
Share-based payment	-	3,515	-	3,515
Balance at 30 June 2021	345,420	4,531	(311,591)	38,360
Balance at 1 January 2022	392,196	6,791	121,769	520,756
Profit/(loss) for the period	-	-	203,543	203,543
Total comprehensive profit for the period	-	-	203,543	203,543
Share-based payment	-	2,068	-	2,068
Balance at 30 June 2022	392,196	8,859	325,312	726,367

 

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

 

Group Statement of Cash Flows

For the six months ended 30 June 2022

	Notes	30 June  2022  $'000	30 June 2021  $'000
		Unaudited	Unaudited
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations	13	522,664	287,879
Cash received from insurance		8,268	-
Cash received/(paid) on sale/(purchase) of financial instruments		(139)	-
Decommissioning spend		(28,194)	(38,661)
Income taxes paid		(4,224)	(2,276)
Net cash flows from/(used in) operating activities		498,375	246,942
INVESTING ACTIVITIES
Purchase of property, plant and equipment		(52,113)	(14,986)
Purchase of intangible oil and gas assets		(2,578)	(936)
Repayment of Magnus contingent consideration - Profit share	10	-	(968)
Acquisitions		-	(3,000)
Interest received		256	83
Net cash flows (used in)/from investing activities		(54,435)	(19,807)
FINANCING ACTIVITIES
Proceeds of loans and borrowings		67,440	-
Repayment of loans and borrowings		(300,089)	(88,170)
Repayment of Magnus contingent consideration - Vendor loan	10	-	(11,362)
Repayment of obligations under leases		(59,279)	(57,286)
Interest paid		(52,513)	(15,795)
Other finance costs paid		-	(1,236)
Net cash flows from/(used in) financing activities		(344,441)	(173,849)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS		99,499	53,286
Net foreign exchange on cash and cash equivalents		(16,441)	(1,082)
Cash and cash equivalents at 1 January		286,662	222,830
CASH AND CASH EQUIVALENTS AT 30 June		369,720	275,034
Reconciliation of cash and cash equivalents
Cash and cash equivalents		360,241	244,331
Restricted cash1		9,479	30,703
Cash and cash equivalents per balance sheet		369,720	275,034

 

(i)   At 30 June 2022, restricted cash includes $7.8 million on deposit relating to bank guarantees for the Group's Malaysian assets and $1.7 million related to cash collateralised letters of credit

 

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

 

Notes to the Half Year Condensed Financial Statements

For the period ended 30 June 2022

 

1.   Corporate information

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

The principal activities of the Company and its subsidiaries (together the 'Group') are responsibly to optimise production, leverage existing infrastructure, deliver a strong decommissioning performance and explore new energy and further decarbonisation opportunities. The Group's half year condensed financial statements for the six months ended 30 June 2022 were authorised for issue in accordance with a resolution of the Board of Directors on 5 September 2022.

2.     Basis of preparation

The interim condensed consolidated financial statements of the Group for the six months ended 30 June 2022 have been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted by the UK. The presentation currency of the Group financial information is US Dollars and all values in the Group financial information are rounded to the nearest thousand ($'000) except where otherwise stated.

The interim report does not include all the information and disclosures required in the annual financial statements and should be read in conjunction with the Group's annual financial statements as at 31 December 2021.

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

Consolidated statutory accounts for the year ended 31 December 2021, on which the auditor gave an unqualified audit report, have been filed with the Registrar of Companies.

The financial statements have been prepared on the going concern basis. Further information relating to the use of the going concern assumption is provided in the 'Going Concern' section of the Financial Review as set out on page 12. The interim financial statements have been reviewed by the auditor and its report to the Company is included within these interim financial statements.

Accounting policies

The accounting policies adopted in the preparation of the interim condensed financial statements for the six months ended 30 June 2022 are materially consistent with those followed in the preparation of the Group's financial statements for the year ended 31 December 2021. Any other standard, interpretation or amendment that was issued but not yet effective has not been adopted by the Group. Critical accounting judgements and key sources of estimation uncertainty were disclosed in the Group's 2021 annual report and accounts. These are reconsidered at the end of each reporting period to determine if any changes are required to judgements and estimates as a result of current market conditions.

Recoverability of asset carrying values - Oil price

The Group's un-hedged oil price assumptions were revised during the first half of 2022 as shown below. The assumptions up to 2024 were increased to reflect the material increase in oil prices in the first half of 2022 following the Russia-Ukraine conflict and improved demand outlook. For periods after 2025, the Group's longer term price assumption is unchanged from that disclosed in the Group's 2021 annual report and accounts at $60/bbl (in real 2021 terms) inflated at 2% per annum from 2025.

 

	Second  half 2022	2023	2024
Brent oil ($/bbl)	100	90	80

 

The price assumptions used at the end of 2021 were $75.0/bbl (2022), $70.0/bbl (2023), $70.0/bbl (2024) and $60.0/bbl real thereafter, inflated at 2.0% per annum from 2025.

The discount rate used in impairment testing has been increased to 11% following the market volatility in the first half of 2022 and the increase in interest rates (2021: 10%).

New and amended standards adopted by the Group

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

Amendments to IFRS 3	Reference to the Conceptual Framework
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

 

 

3.     Segment information

Segment information for the six month period is as follows:

Period ended 30 June 2022 $'000	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations(i)	Consolidated
Revenue and other operating income:
Revenue from contracts with customers	1,032,192	72,471	-	1,104,663	-	1,104,663
Other operating income	1,029	-	138	1,167	(266,995)	(265,828)
Total revenue and other operating income	1,033,221	72,471	138	1,105,830	(266,995)	838,835
Segment profit/(loss)(ii)	536,871	27,042	1,527	565,440	(271,282)	294,158

 

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

 

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

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

 

 

Reconciliation of profit/(loss):

	Period ended 30 June 2022  $'000	Period ended 30 June 2021 $'000
Segment profit/(loss)	565,440	227,596
Finance income	391	102
Finance expense	(111,977)	(116,902)
Gain/(loss) on derivatives(i)	(271,282)	(61,724)
Profit/(loss) before tax	182,572	49,072

 

(i)   Includes $166.1 million realised losses (2021: $24.7 million realised losses) on derivatives and $105.2 million unrealised losses (2021: $37.0 million unrealised losses) on derivatives

 

4.     Remeasurements and exceptional items

Period ended 30 June 2022 $'000	Fair value remeasurement(i)	Impairments  and write offs(ii)	Other(iii)	Total
Revenue and other operating income	(104,672)	-	-	(104,672)
Cost of sales	(481)	-	-	(481)
Net impairment reversal	-	10,122	-	10,122
Other income	4,061	-	-	4,061
Other expense	(30,996)	-	-	(30,996)
Finance costs	-	-	(17,870)	(17,870)
	(132,088)	10,122	(17,870)	(139,836)
Tax on items above	54,461	(4,049)	5,046	55,458
Recognition of undiscounted deferred tax asset(iv)	-	107,895	-	107,895
	(77,627)	113,968	(12,824)	23,517

 

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

 

(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 $104.7 million (2021: $37.0 million). Net other expense relates to the fair value remeasurement of contingent consideration relating to the acquisition of Magnus and associated infrastructure of $26.9 million (note 10) (2021: Other income $27.5 million)

(ii)   Net impairments reversal totalling $10.1 million (note 7) (2021: nil)

(iii)  Other items mainly relate to unwinding of discount on contingent consideration on the 75% acquisition of Magnus and associated infrastructure of $17.9 million (note 10) (2021: $30.3 million)

(iv)  Non-cash deferred tax credit (2021: charge) following a reassessment of deferred tax balances reflecting revisions to forecast assumptions

5.     Revenue

Revenue and other operating income

The Group generates revenue through the sale of crude oil, gas and condensate to third parties, and through the provision of infrastructure to its customers for tariff income. Further details are described in the last annual financial statements.

	Period ended 30 June 2022 $'000	Period ended 30 June 2021 $'000
Revenue from contracts with customers:
Revenue from crude oil sales	851,206	490,536
Revenue from gas and condensate sales(i)	252,907	57,850
Tariff revenue	550	467
Total revenue from contracts with customers	1,104,663	548,853
Rental income from vessels	-	702
Realised (losses)/gains on oil derivative contracts	(162,323)	(32,908)
Other	1,167	1,640
Business performance revenue and other operating income	943,507	518,287
Unrealised (losses)/gains on oil derivative contracts(ii)	(104,672)	(36,973)
Total revenue and other operating income	838,835	481,314

 

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

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

 

6.     Earnings per share

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

Basic and diluted earnings per share are calculated as follows:

	Profit/(loss) after tax				Weighted average number of Ordinary shares		Earnings per share
	Period ended 30 June				Period ended 30 June		Period ended 30 June
	2022 $'000		2021  $'000		2022 million	2021 million	2022 $		2021 $
Basic	203,543	(56,372)		1,833.9		1,649.3		0.111		(0.034)
Dilutive potential of Ordinary shares granted under share-based incentive schemes	-	-		36.9		26.7		-		-
Diluted(i)	203,543	(56,372)		1,870.8		1,676.0		0.109		(0.034)
Basic (excluding remeasurements and exceptional items)	180,026	108,265		1,833.9		1,649.3		0.098		0.066
Diluted (excluding remeasurements and exceptional items)(i)	180,026	108,265		1,870.8		1,676.0		0.096		0.065

 

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

 

 

7.     Property, plant and equipment

 

	Oil and gas assets $'000	Office furniture, fixtures and fittings $'000	Right-of-use assets $'000	Total $'000
Cost:
At 1 January 2022	8,997,353	65,385	867,893	9,930,631
Additions	38,027	532	16,558	55,117
Disposal	-	-	(12,869)	(12,869)
Change in decommissioning provision	(35,301)	-	-	(35,301)
At 30 June 2022	9,000,079	65,917	871,582	9,937,578
Accumulated depreciation, depletion and impairment:
At 1 January 2022	6,650,304	53,829	404,500	7,108,633
Charge for the year	145,524	1,489	30,491	177,504
Net impairment reversal	(10,122)	-	-	(10,122)
Disposal	-	-	(11,314)	(11,314)
At 30 June 2022	6,785,706	55,318	423,677	7,264,701
Net carrying amount:
At 30 June 2022	2,214,373	10,599	447,905	2,672,877
At 31 December 2021	2,347,049	11,556	463,393	2,821,998
At 30 June 2021	2,030,409	12,569	468,857	2,511,835

 

Impairments

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

 

	Impairment reversal		Recoverable amount(i)
	Period ended 30 June 2022 $'000	Year ended 31 December 2021 $'000	Period ended 30 June 2022 $'000	Year ended 31 December 2021 $'000
North Sea	10,122	39,715	104,465	1,496,219
Net pre-tax impairment reversal	10,122	39,715

 

(i)    Recoverable amount has been determined on a fair value less costs of disposal basis. The amounts disclosed above are in respect of assets where an impairment (or reversal) has been recorded. Assets which did not have any impairment or reversal are excluded from the amounts disclosed

 

The 2022 net impairment reversal of $10.1 million relates to producing assets in the UK North Sea. The increase in EnQuest's near-term future oil price assumptions were largely offset by the increase in discount rate from 10% to 11% and impact of tax including the recently introduced UK Energy Profit Levy. The CGUs on which impairment reversals relate was $14.6m for the GKA and Scolty/Crathes CGU. Impairment losses of $4.5 million were incurred relating to the Alba CGU.   

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.

Sensitivity analyses

Management tested the impact of a change in cash flows in FVLCD impairment testing arising from a 10% change 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 $244.0 million, which is approximately 9% of the net book value of property, plant and equipment as at 30 June 2022. Price increases could indicatively lead to an increase in the carrying amount of EnQuest's oil and gas properties by approximately $202.2 million.

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 changes in costs and to business plans, phasing of development, levels of reserves and resources, and production volumes. As the extent of a price reduction increases, the more likely it is that costs would decrease across the industry. The oil price sensitivity analysis therefore does not reflect a linear relationship between price and value that can be extrapolated.

Management also tested the impact of a 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, a net impairment would have been recognised in first half of 2022 of approximately $34.6 million, a difference of $44.7 million on the net impairment reversal recognised at 30 June 2022. If the discount rate was one percentage point lower, the net impairment reversal recognised would have been approximately $37.7 million higher.

 

8.     Loans and borrowings

	30 June  2022 $'000	31 December 2021 $'000
Borrowings	115,676	401,614
Bonds	1,125,069	1,081,596
	1,240,745	1,483,210

 

Borrowings

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

	30 June  2022			31 December  2021
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
RBL(i)	115,000	(7,673)	107,327	415,000	(23,250)	391,750
SVT Working Capital facility	8,349	-	8,349	9,864	-	9,864
Total borrowings	123,349	(7,673)	115,676	424,864	(23,250)	401,614
Due within one year			65,676			210,505
Due after more than one year			50,000			191,109
Total borrowings			115,676			401,614

(i)      During the period to 30 June 2022, the Group repaid $300.0 million of the outstanding principal, well ahead of the planned amortisation schedule. At 30 June 2022, after allowing for letter of credit utilisation of $52.7 million, $97.3 million remained available for drawdown under the facility.

 

Bonds

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

	30 June  2022			31 December  2021
	Principal $'000	Fees $'000	Total $'000	Principal $'000	Fees $'000	Total $'000
High yield bond(i)	827,166	(1,254)	825,912	827,166	(1,725)	825,441
Retail bond 7%(ii)	136,096	-	136,096	256,574	(419)	256,155
Retail bond 9%(iii)	163,061	-	163,061	-	-	-
Total bonds due after more than one year	1,126,323	(1,254)	1,125,069	1,083,740	(2,144)	1,081,596

(i)    The total carrying value of the high yield bond as at 30 June 2022 is $825.9 million (2021: $825.4 million). This includes bond principal of $827.2 million (2021: $827.2 million) less unamortised fees of $1.3 million (2021: $1.7 million). The high yield bond does not include accrued interest, including IFRS 9 EIR adjustment, of $14.1 million (2021: $14.8 million) which is reported within trade and other payables.

(ii)   During the period, following the successful exchange and cash offer, £79.3 million of the Retail bond 7% were exchanged for the Retail Bond 9%. This resulted in a reduction of principal by $104.4 million. The total carrying value of the Retail bond 7% at 30 June 2022 is $136.1 million (2021: $256.2 million). This includes bond principal of $136.1 million (2021: $256.6 million) less unamortised fees of nil (2021: $0.4 million). The Retail bond 7% does not include accrued interest, including IFRS 9 EIR adjustment, of $3.8 million (2021: $13.5 million), which is reported within trade and other payables.

(iii)  On 27 April 2022, the Group issued a new 9% retail bond ('Retail bond 9%'), following a successful exchange and open offer. The principal of the Retail Bond 9% raised by the exchange and open offer totalled £133.3 million. This was made up of £79.3 million exchanging from the Retail Bond 7% and £54.0 million new bond holders. The total carrying value of the Retail bond 9% as at 30 June 2022 is $163.1 million. This does not include accrued interest, including IFRS 9 EIR adjustment, of $2.2 million, which is reported within trade and other payables.

 

9.     Other financial assets and financial liabilities

(a) Summary as at 30 June 2022

	30 June  2022		31 December  2021
	Assets $'000	Liabilities $'000	Assets $'000	Liabilities $'000
Fair value through profit or loss:
Derivative commodity contracts	1,203	161,780	-	55,245
Derivative foreign exchange contracts	-	-	382	-
Commodity futures	-	-	-	2
Derivative UKAs contracts	-	9	90	-
Total current	1,203	161,789	472	55,247
Fair value through profit or loss:
Quoted equity shares	6	-	6	-
Total non-current	6	-	6	-

 

 

(b) Income statement impact

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

Period ended 30 June 2022	Revenue and other operating income		Cost of sales
	Realised $'000	Unrealised $'000	Realised $'000	Unrealised $'000
Commodity options	(165,053)	(105,977)	-	-
Commodity swaps	1,387	1,303	-	-
Commodity futures	1,343	2	-	-
Foreign exchange contracts	-	-	(3,546)	(382)
UKA contracts	-	-	(260)	(99)
	(162,323)	(104,672)	(3,806)	(481)

 

 

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

 

(c) Fair value measurement

30 June 2022			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
Oil commodity derivative contracts				1,203		-		1,203		-
Quoted equity shares				6		6		-		-
Total financial assets measured at fair value				1,209		6		1,203		-
Liabilities measured at fair value:
Derivative financial liabilities at FVPL
Oil commodity derivative contracts				161,789		-		161,789		-
Forward UKA contracts				9		-		9		-
Other financial liabilities measured at FVPL
Contingent consideration				457,137		-		-		457,137
Total liabilities measured at fair value				618,935		-		161,798		457,137
Liabilities measured at amortised cost for which fair values are disclosed below:
Interest-bearing loans and borrowings			8	123,349		-		-		123,349
Obligations under leases				540,045		-		-		540,045
Retail bond 7%			8	132,353		132,353		-		-
Retail bond 9%			8	158,789		158,789		-		-
High yield bond			8	740,876		740,876		-		-
Total liabilities measured at amortised cost for which fair values are disclosed				1,695,412		1,032,018		-		663,394
30 June 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:
Other financial assets at FVPL
Forward UKA contracts		90			-		90		-
Forward foreign currency contracts		382			-		382		-
Quoted equity shares		6			6		-		-
Total financial assets measured at fair value		478			6		472		-
Liabilities measured at fair value:
Derivative financial liabilities at FVPL
Oil commodity derivative contracts		55,247			-		55,247		-
Other financial liabilities measured at FVPL
Contingent consideration		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	8	424,864			-		-		424,864
Obligations under leases		570,781			-		-		570,781
Retail bond 7%	8	244,387			244,387		-		-
High yield bond	8	773,499			773,499		-		-
Total liabilities measured at amortised cost for which fair values are disclosed		2,013,531			1,017,886		-		995,645

 

Fair value hierarchy

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

 

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

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

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

 

Derivative financial instruments are valued by counterparties, with the valuations reviewed internally and corroborated with readily available market data (Level 2). Contingent consideration is measured at FVPL using the Level 3 valuation processes disclosed in note 10. There have been no transfers between Level 1 and Level 2 during the period (2021: no transfers).

 

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

 

10.  Contingent consideration

 

	Magnus 75% $'000	Magnus Linked decommissioning liability $'000	Golden Eagle Contingent Consideration $'000	Total $'000
At 31 December 2021	344,627	20,976	45,175	410,778
Change in fair value	30,996	(4,061)	-	26,935
Unwinding of discount	16,821	1,049	1,554	19,424
At 30 June 2022	392,444	17,964	46,729	457,137
Classified as:
Current	52,024	2,680	-	54,704
Non-current	340,420	15,284	46,729	402,433
	392,444	17,964	46,729	457,137

 

75% Magnus acquisition contingent consideration

The contingent consideration was fair valued at 30 June 2022, which resulted in an increase in fair value of $31.0 million reflecting a change in the Groups short term oil price assumptions partially offset by a 1% increase in the discount rate to 11% (2021: decrease of $28.7 million reflecting the change in the payment profiles). The fair value accounting effect and finance costs of $16.8 million (2021: $29.6 million) on the contingent consideration were recognised through remeasurements and exceptional items in the Group income statement. Within the statement of cash flows, the profit share element of the repayment, nil (2021: $1.0 million), is disclosed separately under investing activities. At 30 June 2022, the contingent consideration was $392.4 million (31 December 2021: $344.6 million). The contingent profit sharing arrangement cap of $1 billion was not met as at 30 June 2022 in the present value calculations (2021: cap was not met).

Magnus decommissioning-linked contingent consideration

As part of the Magnus and associated interests acquisition, BP retained the decommissioning liability in respect of the existing wells and infrastructure and EnQuest agreed to pay additional consideration in relation to the management of the physical decommissioning costs of Magnus. At 30 June 2022, the amount due to BP calculated on an after-tax basis by reference to 30% of BP's decommissioning costs on Magnus was $18.0 million (31 December 2021: $21.0 million).

Golden Eagle contingent consideration

Part of the Golden Eagle acquisition consideration included an amount that was contingent on the average oil price between July 2021 and June 2023. 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 30 June 2022, the contingent consideration was valued at $46.7 million.

 

11.  Provisions

 

	Decommissioning provision $'000	Thistle decommissioning provision $'000	Other provisions $'000	Total $'000
At 31 December 2021	835,721	43,930	15,291	894,942
Additions	1,450	-	1,223	2,673
Changes in estimates	(58,333)	(9,260)	(730)	(68,323)
Unwinding of discount	8,500	439	-	8,939
Utilisation	(22,657)	(1,247)	(500)	(24,404)
Other	-	(86)	(78)	(164)
At 30 June 2022	764,681	33,776	15,206	813,663
Classified as:
Current	58,433	9,203	15,206	82,842
Non-current	706,248	24,573	-	730,821
	764,681	33,776	15,206	813,663

 

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. The Group's decommissioning provision has reduced by $71.0 million in the period, primarily reflecting a favourable foreign exchange rate movement and the ongoing decommissioning programmes at Heather and the Dons. At 30 June 2022, an estimated $322.7 million is expected to be utilised between one and five years (31 December 2021: $409.6 million), $60.1 million within six to ten years (31 December 2021: $81.4 million), and the remainder in later periods.

The Group enters into surety bonds principally to provide security for its decommissioning obligations. At 30 June 2022, the Group held surety bonds totalling $230.2 million (31 December 2021: $240.8 million).

Thistle decommissioning provision

At 30 June 2022, the amount due to BP by reference to 7.5% of BP's decommissioning costs on Thistle and Deveron was $33.8 million (31 December 2021: $43.9 million), with the reduction mainly reflecting the change in estimate and utilisation in the period. Unwinding of discount of $0.4 million is included within finance income for the year ended 30 June 2022 (2021: $0.5 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. To date $4.4 million has been utilised and at 30 June 2022, the provision was $1.5 million (31 December 2021: $1.5 million).

During 2021, the Group recognised $8.2 million in relation to disputes with third-party contractors. In 2022, one dispute was settled for $0.5 million and the other dispute is ongoing. At 30 June 2022, the provision was $7.3 million (31 December 2021: $8.2 million).

12.  Commitments and contingencies

Capital commitments

At 30 June 2022, the Group had capital commitments amounting to $11.0 million (31 December 2021: $1.9 million).

 

Other commitments

In the normal course of business, the Group will obtain surety bonds, letters of credit and guarantees. At 30 June 2022, the Group held surety bonds totalling $230.2 million (31 December 2021: $240.8 million) to provide security for its decommissioning obligations.

 

Contingencies

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

13.  Cash flow information

 

Cash generated from operations

	Notes	Period ended 30 June 2022 $'000	Period ended 30 June 2021 $'000
Profit/(loss) before tax		182,572	49,072
Depreciation	7	3,295	3,915
Depletion	7	174,209	153,085
Net impairment reversal		(10,122)	-
Net disposal/write down of inventory		(360)	983
Change in fair value of investments		-	1
Share-based payment charge		2,068	3,515
Change in contingent consideration		46,359	2,810
Change in provisions		(22,860)	14,754
Amortisation of option premiums		658	-
Unrealised (gain)/loss on commodity financial instruments		104,672	36,973
Unrealised (gain)/loss on other financial instruments		481	-
Unrealised exchange (gain)/loss		(20,686)	4,796
Net finance expense		84,777	78,042
Operating profit before working capital changes		545,063	347,946
Decrease/(increase) in trade and other receivables		2,214	(121,006)
Decrease/(increase) in inventories		(17,771)	470
(Decrease)/increase in trade and other payables		(6,842)	60,469
Cash generated from operations		522,664	287,879

 

Changes in liabilities arising from financing activities

	Loans and borrowings $'000	Bonds $'000	Lease liabilities $'000	Total $'000
At 31 December 2021	(402,065)	(1,109,920)	(570,781)	(2,082,766)
Cash movements:
Repayments of loans and borrowings	300,089	-	-	300,089
Drawdown of loans and borrowings	-	(71,163)	-	(71,163)
Repayment of lease liabilities	-	-	59,279	59,279
Cash interest paid in period	7,775	39,444	-	47,219
Non-cash movements:
Additions	-	-	(16,294)	(16,294)
Interest/finance charge payable	(8,589)	(31,477)	(20,045)	(60,111)
Fee amortisation	(15,577)	(889)	-	(16,466)
Foreign exchange adjustments	1,426	28,941	6,364	36,731
Disposal	-	-	1,432	1,432
Other non-cash movements	45	-	-	45
At 30 June 2022	(116,896)	(1,145,064)	(540,045)	(1,802,005)

 

Reconciliation of carrying value

	Loans and borrowings $'000	Bonds $'000	Lease liabilities $'000	Total $'000
Principal	(123,349)	(1,126,323)	(540,045)	(1,789,717)
Unamortised fees	7,673	1,254	-	8,927
Accrued interest	(1,220)	(19,995)	-	(21,215)
At 30 June 2022	(116,896)	(1,145,064)	(540,045)	(1,802,005)

 

14.  Subsequent events

Energy Profits Levy

On 26 May 2022, the UK Government announced the introduction of an Energy Profits Levy ('EPL') on the profits earned from the production of oil and gas in the UK with effect from that date. The EPL enabling legislation, the Energy (Oil and Gas) Profits Levy Act 2022, was substantively enacted on 11 July 2022. The EPL is charged at the rate of 25 per cent on taxable profits in addition to ring fence corporation tax of 30 per cent and the Supplementary Charge of 10 per cent. The EPL tax is a temporary measure and as enacted will cease to apply on 31 December 2025.

As the legislation was not substantively enacted as at 30 June 2022, the tax charge in the half-year results does not include the impact of EPL for the period which will instead be reflected in the second half of 2022. If the EPL had been considered in the interim period, a cash tax liability of $20.0 million would be recognised of which $5.6 million would have been in respect of Business Performance in the period 26 May 2022 to 30 June 2022.

Had the EPL been fully enacted before 30 June 2022, these half-year results would have recognised an additional net deferred tax liability of $106.6 million at the period end.

The amounts disclosed above are provisional and the overall current and deferred tax impact for the year will be included in the full-year results.

Statement of Directors' Responsibilities

 

We confirm that to the best of our knowledge:

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

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

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

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

 

By the order of the Board

 

 

 

Amjad Bseisu

Chief Executive

 

5 September 2022

Independent review report to EnQuest PLC

Conclusion

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2022 which comprises the Group Income Statement, the Group Balance Sheet, the Group Statement of Changes in Equity, the Group Statement of Cash Flows and related notes 1 to 14.

 

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2022 is not prepared, in all material respects, in accordance with United Kingdom adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

 

Basis for Conclusion

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

 

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

 

Conclusion Relating to Going Concern

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

 

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

 

Responsibilities of the directors

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

 

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

 

Auditor's Responsibilities for the review of the financial information

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

 

Use of our report

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

 

 

 

Deloitte LLP

Statutory Auditor

London, United Kingdom

5 September 2022

Glossary - Non-GAAP measures

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

Business performance net profit attributable to EnQuest PLC shareholders	Period ended 30 June 2022 $'000	Period ended 30 June 2021 $'000
Reported net profit/(loss) (A)	203,543	(56,372)
Adjustments - remeasurements and exceptional items:
Unrealised (losses)/gains on derivative contracts (note 9b)	(105,153)	(36,973)
Net impairment (charge)/reversal to oil and gas assets (note 4)	10,122	-
Unwind and interest on contingent consideration (note 10)	(17,870)	(30,299)
Change in fair value of contingent consideration (note 10)	(26,935)	27,490
Pre-tax remeasurements and exceptional items (B)	(139,836)	(39,782)
Tax on remeasurements and exceptional items (note 4) (C)	163,353	(124,855)
Post-tax remeasurements and exceptional items (D = B + C)	23,517	(164,637)
Business performance net profit attributable to EnQuest PLC shareholders (A - D)	180,026	108,265

 

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/(loss) from operations before tax and finance income/(costs).

 

Adjusted EBITDA	Period ended 30 June 2022 $'000	Period ended 30 June 2021 $'000
Reported profit/(loss) from operations before tax and finance income/(costs)	294,158	165,872
Adjustments:
Remeasurements and exceptional items	121,966	9,483
Depletion and depreciation (note 7)	177,504	157,000
Inventory revaluation	(360)	983
Change in provision	(32,292)	5,718
Net foreign exchange (gain)/loss	(24,693)	6,360
Adjusted EBITDA (E)	536,283	345,416

 

Total cash and available facilities is a measure of the Group's liquidity at the end of the reporting period. The Group believes this is a useful metric as it is an important reference point for the Group's going concern assessment, see page 12.

Total cash and available facilities	Period ended 30 June 2022 $'000	Year ended 31 December 2021 $'000
Available cash	360,241	276,970
Restricted cash	9,479	9,691
Total cash and cash equivalents (F)	369,720	286,661
Available facilities	265,000	500,000
RBL - Drawn down	(115,000)	(415,000)
Letter of credit	(52,700)	(53,000)
Available undrawn facility (G)	97,300	32,000
Total cash and available facilities (F + G)	467,020	318,661

 

Net debt is a liquidity measure that shows how much debt a company has on its balance sheet compared to its cash and cash equivalents. With de-leveraging a strategic priority, the Group believes this is a useful metric to demonstrate progress in this regard. It is also an important reference point for the Group's going concern assessment, see page 12.

 

Net debt	Period ended 30 June 2022 $'000	Year ended 31 December 2021 $'000
Borrowings (note 8):
RBL	107,327	391,750
SVT Working Capital facility	8,349	9,864
Borrowings (H)	115,676	401,614
Bonds (note 8):
High yield bond	825,912	825,441
Retail bond 7%	136,096	256,155
Retail bond 9%	163,061	-
Bonds (I)	1,125,069	1,081,596
Non-cash accounting adjustments (note 8):
Unamortised fees on loans and borrowings	7,673	23,250
Unamortised fees on bonds	1,254	2,144
Non-cash accounting adjustments (J)	8,927	25,394
Debt (H + I + J) (K)	1,249,672	1,508,604
Less: Cash and cash equivalents (E)	369,720	286,661
Net debt/(cash) (K - F) (L)	879,952	1,221,943

 

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	Period ended 30 June 2022 $'000	Year ended 31 December 2021 $'000
Net debt (L)	879,952	1,221,943
Business performance adjusted EBITDA (last 12 months) (E)	933,737	742,868
Net debt/adjusted EBITDA (L/E)	0.9	1.6

 

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

 

Cash capital and decommissioning expense	Period ended 30 June 2022 $'000	Period ended 30 June 2021 $'000
Reported net cash flows (used in)/from investing activities	(54,435)	(19,807)
Adjustments:
Repayment of Magnus contingent consideration - Profit share	-	968
Acquisitions	-	3,000
Interest received	(256)	(83)
Cash capital expenditure	(54,691)	(15,922)
Decommissioning spend	(28,194)	(38,661)
Cash capital and decommissioning expense	(82,885)	(54,583)

 

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. This has resulted in a $3.0 million increase to 30 June 2021 FCF.

 

Free cash flow	Period ended 30 June 2022 $'000	Period ended 30 June 2021 $'000
Net cash flows from/(used in) operating activities	498,375	246,942
Net cash flows from/(used in) investing activities	(54,435)	(19,807)
Net cash flows from/(used in) financing activities	(344,441)	(173,849)
Adjustments:
Proceeds of loans and borrowings	(67,440)	-
Repayment of loans and borrowings	300,089	88,170
Acquisitions	-	3,000
Free cash flow	332,148	144,456

 

Revenue from sales	Period ended 30 June 2022 $'000	Period ended 30 June 2021 $'000
Revenue from crude oil sales (note 5) (M)	851,206	490,536
Revenue from gas and condensate sales (note 5) (N)	252,907	57,850
Realised (losses)/gains on oil derivative contracts (note 5) (P)	(162,323)	(32,908)

 

Barrels equivalent sales	Period ended 30 June 2022 kboe	Period ended 30 June 2021 kboe
Sales of crude oil (Q)	7,667	7,288
Sales of gas and condensate(i)	1,607	1,314
Total sales (R)	9,274	8,602

(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	Period ended 30 June 2022 $/Boe	Period ended 30 June 2021 $/Boe
Average realised oil price, excluding hedging (M/Q)	111.0	67.3
Average realised oil price, including hedging ((M + P)/Q)	89.9	62.8

 

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	Period ended 30 June 2022 $'000	Period ended 30 June 2021 $'000
Reported cost of sales	586,082	333,262
Adjustments:
Remeasurements and exceptional items	(481)	-
Depletion of oil and gas assets	(174,209)	(153,085)
Credit/(charge) relating to the Group's lifting position and inventory	29,896	26,060
Other cost of sales	(232,904)	(53,137)
Operating costs	208,384	153,100
Less realised (gain)/loss on derivative contracts (S)	3,806	(8,157)
Operating costs directly attributable to production	204,578	161,257
Comprising of:
Production costs (T)	181,166	139,537
Tariff and transportation expenses (U)	23,412	21,720
Operating costs directly attributable to production	204,578	161,257

 

Barrels equivalent produced	Period ended 30 June 2022 kboe	Period ended 30 June 2021 kboe
Total produced (working interest) (V)	9,000	8,360

 

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	Period ended 30 June 2022 $/Boe	Period ended 30 June 2021 $/Boe
Production costs (T/V)	20.1	16.7
Tariff and transportation expenses (U/V)	2.6	2.6
Total unit opex ((T + U)/V)	22.7	19.3
Realised (gain)/loss on derivative contracts (S/V)	0.4	(1.0)
Total unit opex including hedging ((S + T+ U)/V)	23.1	18.3