Enquest Regulatory News (ENQ)

Production increased 27% year on year with higher cash generation;

debt reduction ongoing with net debt:EBITDA ratio* at 1.8x

Results for the six months ended 30 June 2019

 5 September 2019

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 2018 and the Balance Sheet as at 31 December 2018.

Highlights and outlook

§ Group net production up 27.0%, averaging 68,548 Boepd in the six months to end June 2019; full year 2019 guidance of 63,000 Boepd to 70,000 Boepd unchanged

§ Improved production efficiency at Kraken in the second quarter resulted in average gross production of 32,776 Bopd in the first half of 2019. Full year guidance of 30,000 Bopd to 35,000 Bopd remains unchanged. Worcester two-well drilling programme planned for 2020 as the first Western Flank development

§ Magnus performance in line with expectations. Planned maintenance shutdown completed in the period. Two-well drilling programme to commence in the fourth quarter

§ PM8/Seligi performance above expectations reflecting the ongoing successful idle well restoration programme and high production efficiency. Two-well drilling programme commenced in July

§ Increased revenue of $858.2 million (2018: $548.3 million) and EBITDA of $525.9 million (2018: $311.9 million) driven by higher production volumes and realised prices, including the impact of the Group's hedge programme

§ Operating expenditure increased to $248.4 million (2018: $220.6 million) with unit operating costs reduced to $20.1/boe (2018: $22.6/boe), reflecting the acquisition of additional interest in Magnus

§ Material increase in cash generated from operations at $426.2 million (2018: $318.3 million); cash capital expenditure of $124.6 million (2018: $125.8 million), with guidance unchanged

§ Free cash flow** generation of $138.3 million (2018: $53.6 million) has enabled continuing debt reduction

End June net debt reduced by $136.6 million from year end; net debt:EBITDA ratio* of 1.8x

§ At 30 June 2019, net debt was reduced to $1,637.9 million (end 2018: $1,774.5 million) with cash and available bank facilities amounting to $248.5 million (end 2018: $309.0 million)

§ At the end of July, the Group's credit facility had reduced to $615.0 million following the early repayment of $65.0 million of the scheduled amortisation, with $55.0 million repaid in June and $10.0 million repaid in July. The remaining $35.0 million of the scheduled amortisation will be paid by 1 October

§ Net debt:EBITDA ratio* at the half year was 1.8x (end 2018: 2.5x), ahead of target to be below 2x by the end of 2019

* based on last twelve months EBITDA to end June 2019 and net debt at 30 June 2019

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

2019 cash flow supported by oil price hedges

§ For full year 2019, the Group's hedge programme covers c.12.5 MMbbls. For the second half of 2019, the Group has c.4.6 MMbbls of oil hedges in place. Approximately 3.9 MMbbls are hedged at an average floor price of c.$66/bbl, with a further c.0.7 MMbbls hedged with an average floor price of c.$56/bbl in accordance with the Oz Management facility agreement 

Board change

§ EnQuest has appointed Martin Houston as Chairman of the Group with effect from 1 October 2019, replacing Jock Lennox who will step down from the Board on 30 September 2019 (See separate announcement)

EnQuest Chief Executive, Amjad Bseisu, said:

"The Group has delivered a strong performance in the first half of 2019. Production was towards the top end of our full year guidance range and we continue to control our operating expenditures, with unit opex of $20/boe in the period.

"We have generated strong cash flows in the period and significantly reduced our debt, with our net debt:EBITDA ratio at 1.8x, ahead of our target to be below 2x by the end of 2019.

"We remain confident in achieving our 2019 production guidance of 63,000 to 70,000 Boepd. Our two pipeline projects have been completed ahead of schedule and budget and our annual maintenance programme is expected to be concluded around the end of the third quarter. Drilling is underway in Malaysia with our two-well campaign and drilling at Magnus is due to start in the fourth quarter.

"The Worcester development at Kraken, planned for 2020, will utilise our existing infrastructure and is the first step in developing the material resource present in the Western Flank. We continue to assess options to develop the significant potential within our reserves and resources across our portfolio, particularly at Kraken, Magnus and PM8/Seligi."

Production and financial information

* Including gains of $7.6 million (2018: loss of $77.3 million) associated with EnQuest's oil price hedges. ** EBITDA is calculated on a Business performance basis. It is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation, foreign exchange movements, inventory revaluation and the realised gain/loss on foreign currency derivatives related to capital expenditure. *** 2018 restated to reflect the impact of the October 2018 rights issue.**** Net (debt)/cash represents cash and cash equivalents less borrowings, stated excluding accrued interest and the net-off of unamortised fees and IFRS 9 Financial Instruments adjustments

Summary financial review of H1 2019

 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 2018 and the Balance Sheet as at 31 December 2018.

Revenue was $858.2 million for the six months ended 30 June 2019 compared with $548.3 million for the same period in 2018. This increase was driven by material growth in the Group's production primarily reflecting the contribution from Magnus, including the impact of increased gas and condensate sales. Group revenue is predominantly derived from crude oil sales and for the six months ended 30 June 2019, crude oil sales totalled $761.9 million compared with $608.9 million for the comparative period in 2018. Revenue from the sale of gas and condensate in the period was $79.9 million (2018: $10.7 million) reflecting additional gas sales, including purchased gas not required for injection activities, at Magnus.

The commodity hedge programme resulted in realised gains of $7.6 million in the first half of 2019 (2018: realised loss of $77.3 million). Consequently, the Group's blended average realised oil price was $66.1/bbl for the six months ended 30 June 2019, compared to $59.5/bbl received during the first half of 2018. Excluding the impact of hedging, the average realised oil price was $65.4/bbl in the first half of 2019, compared to $68.1/bbl received during the first half of 2018.

Cost of sales were $588.3 million for the six months ended 30 June 2019 compared with $447.5 million for the same period in 2018. Operating costs increased by $27.8 million to $248.4 million, primarily reflecting the acquisition of the additional equity interest in Magnus. The Group's average unit operating cost has decreased by 11.1% to $20.1/Boe (2018: $22.6/Boe). Other costs increased by $113.0 million to $339.9 million (2018: $226.9 million) reflecting higher production driven depletion charges, a reduction in the Group's net underlift position and higher purchased gas costs. Magnus third-party gas purchases not required for injection activities are now pass through costs having previously been recognised in operating expense.

EBITDA for the six months ended 30 June 2019 increased significantly to $525.9 million compared with $311.9 million for the same period in 2018. This was driven by higher revenue partially offset by higher cost of sales.

The tax charge for the six months ended 30 June 2019 was $36.2 million (2018: $23.0 million tax credit).

The Group's reported cash generated from operations for the six months ended 30 June 2019 was $426.2 million (2018: $318.3 million) driven by higher production and realised prices.

Remeasurement and exceptional items were a net loss of $120.0 million before tax for the six months ended 30 June 2019 (2018: gain of $34.5 million). Revenue included unrealised losses of $42.9 million in respect of the mark to market movement on the Group's commodity contracts from 31 December 2018 (2018: unrealised gains of $2.5 million). Other remeasurement and exceptional items in the first half of 2019 also include a charge to the statement of comprehensive income as a result of an increase in the fair value relating to the contingent consideration on the 75% acquisition of Magnus and associated infrastructure of $26.9 million, which reflects the Group's expectations of continued strong performance at Magnus, $28.1 million unwinding of discount on the end 2018 contingent consideration balance and the provision for settlement of the historical KUFPEC claim of $15.6 million.

EnQuest's net debt decreased by $136.6 million from $1,774.5 million at the end of 2018 to $1,637.9 million at 30 June 2019. Net debt at 30 June 2019 includes $132.5 million of inception to date interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing ('PIK'), compared to $132.0 million at 31 December 2018.

UK corporate tax losses and allowances at 30 June 2019 decreased to $3,090.4 million (2018: $3,225.3 million).

Operating review

Production details

Northern North Sea operations

Average production in the six months to end June 2019 of 30,215 Boepd was 67.8% higher than the same period in 2018, primarily driven by the contribution from additional equity in Magnus.

At Magnus, production performance remained in line with expectations with production efficiency of around 80%, including the impact of the planned three-week shutdown in May to undertake safety-critical maintenance and execute the Dunlin bypass pipeline project tie-in works. The Group's revised reservoir management strategy requires less gas injection, leading to lower operating expenditures as the cost of gas purchased from third parties under a long term contract is now recognised in other cost of sales. The Group remains on-track to commence the planned two-well drilling programme in the fourth quarter and a number of economic, drillable targets have been identified to start to develop the Group's estimated 50 MMboe of 2C resources at Magnus. With material reserves and resources, Magnus provides the opportunity for long-term, low-cost reserves and production increases.

Production and water injection efficiency above 90% in the period resulted in a good performance at Thistle. Planned well abandonments continue to be successfully executed in line with the Group's asset life extension strategy. Strong operational execution and cost control has allowed the Group to increase the 2019 abandonment project scope from five to nine wells while expecting to remain within the original budget.

At the Dons fields, production was in line with the Group's expectations. Good production and reservoir performance was offset by lower than expected water injection efficiency in the first quarter reflecting water injection pump failures. In June, the Dunlin bypass pipeline project was successfully completed 18 days ahead of schedule, with final commissioning work undertaken during the Dons planned annual maintenance shutdown. Subsequently, Thistle production was transferred to the new export route without incurring any production downtime.

Single compressor operations and reliability issues in the first quarter of 2019 impacted production in the period at Heather, although well intervention and production optimisation work at H67 and H56 are expected to improve performance in the second half of the year. The first phase of the Group's 2019 well abandonment programme was successfully completed below budget, with preliminary abandonment work on a further 11 wells to be conducted in the second half of the year ahead of the 2020 programme. The three-week planned maintenance shutdown was completed in August.

EnQuest has continued to achieve high plant availability and deliver safe and stable operations at the Sullom Voe Terminal. In July, the Group announced essential organisational changes to ensure the terminal remains competitive for existing and future business, to deliver the required level of service to its customers, to help Maximise Economic Recovery in the UKCS and provide long term employment opportunities.

Central North Sea operations

Average production in the six months to end June 2019 of 6,627 Boepd was 8.5% higher than the same period in 2018. Production efficiency at Alma/Galia has been over 95% in 2019 following the replacement of three Electric Submersible Pumps in 2018, although the reservoir continues to decline. The focus remains on production optimisation, cost reduction and the preparation of detailed decommissioning plans.

At Scolty/Crathes, production was stable prior to the third quarter shutdown for planned maintenance and connection of the replacement pipeline. The pipeline project was completed ahead of budget and schedule. Production began in early September and is expected to increase significantly compared with the field's pre-shutdown performance.

High levels of production and water injection efficiency in the Greater Kittiwake Area have delivered a strong production performance in the period. The short planned shutdown was completed in July in line with expectations. Output from Alba has been in line with the Group's expectations.

Kraken

Average gross production in the six months to end June 2019 of 32,776 Bopd was in line with guidance. Production efficiency was improved following the resumption of a two-train operation in mid-March, averaging around 80% in the second quarter of 2019, up materially on the first quarter of the year (c.55%). EnQuest has been working closely with the FPSO operator, Bumi Armada, to improve production uptime. Notable successes have been in the power systems, including greater engine stability and power pump performance, and more effective offshore spares management and FPSO maintenance processes. Completion of the DC4 drilling programme in March marked the conclusion of the original Kraken field development plan. All three wells continue to perform ahead of expectations.

Overall subsurface and wells performance has remained strong. Stable water cut levels and the optimisation of production through improved injector-producer well management has offset the impact of the increase in reservoir voidage as a result of low water injection efficiency in the period, which reflected additional cleaning requirements in the seawater treatment unit.

In July and August, pipework repairs on the FPSO required short unplanned production shutdowns. Production efficiency is returning to a similar level to that delivered in the second quarter of 2019. The Group continues to review the requirements for a planned shutdown in September, with certain work scopes having been opportunistically executed during July.

Strong production efficiency performance remains the Group's operational priority and EnQuest continues to expect Kraken to deliver average production in line with guidance of between 30,000 Bopd and 35,000 Bopd (gross) in 2019.

Since first production in June 2017, more than 21 million barrels of oil have now been produced and 42 cargoes offloaded from the FPSO, with 15 of these cargoes offloaded in 2019. Cargo pricing has seen premiums to Brent and continues to be robust.

The Western Flank Area provides a near-field, economic, development opportunity with around 100 MMbbls of STOIIP. Initial Worcester targets have been high-graded, with development drilling of a producer-injector pair through spare capacity in the existing DC2 sub-sea infrastructure planned for 2020. Pembroke development options continue to be assessed.

Malaysian operations

Average production in Malaysia in the six months to end June 2019 of 8,599 Boepd was 4.5% higher than the same period in 2018.

Production has increased from PM8/Seligi as a result of high production efficiency of over 90% and better than expected performance from the Group's idle well restoration programme, which commenced earlier than planned and has seen ten wells restored to production. The Group's 2019 two-well drilling programme commenced in July with first oil expected by the end of the third quarter as planned, while the planned asset rejuvenation activity is progressing as scheduled. At the end of 2018, the Group had c.20 MMboe of 2P reserves and c.68 MMboe of 2C resources. A large number of low-cost drilling and workover targets have been identified and are being assessed.

Liquidity and net debt

At the end of June 2019, net debt was $1,637.9 million, down $136.6 million from $1,774.5 million at 31 December 2018 reflecting strong operational performance and a higher realised oil price. Total cash and available facilities were $248.5 million, including ring-fenced accounts associated with Magnus, the Oz Management facility and other joint venture accounts totalling $79.1 million.

In June, the Group made an early voluntary repayment of $55.0 million of the scheduled October amortisation, with a further $10.0 million repayment in July which has reduced the Group's credit facility to $615.0 million. The remaining $35.0 million will be repaid by 1 October 2019.

By the end of June, c.7.9 MMbbls of oil hedges had been settled. Approximately 7.1 MMbbls had an average floor price of c.$67/bbl, while c.0.8 MMbbls associated with the Oz Management facility had an average floor price of c.$56/bbl. For the remaining six months of 2019, EnQuest has c.4.6 MMbbls of oil hedges in place. Approximately 3.9 MMbbls are hedged at an average floor price of c.$66/bbl, with a further c.0.7 MMbbls hedged with an average floor price of c.$56/bbl in accordance with the Oz Management facility agreement.

2019 outlook reaffirmed

Group production performance in the period was ahead of the mid-point of guidance of 68,548 Boepd. With a number of planned maintenance shutdowns in the second half of 2019, the Group continues to expect 2019 net production to grow by around 20% to between 63,000 and 70,000 Boepd.

Operating expenditure is now expected to be around $550 million, lower than the $600 million originally guided primarily as a result of the revised reservoir management strategy at Magnus.

Expectations for 2019 capital expenditure remain around $275 million, with the programme weighted towards the second half of the year. The two-well drilling programme at PM8/Seligi commenced in July with the Magnus two-well campaign expected to commence in the fourth quarter.

The Group continues to prioritise debt repayment with an ongoing focus on cost control and capital discipline. Through the second half of 2019, the Group expects overall net debt to EBITDA to continue to reduce. In future, EnQuest intends to operate between 1x and 2x, targeting the lower end of the range.

Appointment of external auditors

In accordance with the Group's policy, a formal audit tender process was conducted resulting in EnQuest appointing Deloitte LLP ('Deloitte') as the Group's external auditors of the Company's financial statements beginning 1 January 2020. Ernst & Young LLP will continue to audit the Group's financial statements for the year ended 31 December 2019.

- Ends -

For further information please contact:

EnQuest PLC Tel: +44 (0)20 7925 4900

Amjad Bseisu (Chief Executive)

Jonathan Swinney (Chief Financial Officer)

Ian Wood (Communications & Investor Relations) 

Tulchan Communications Tel: +44 (0)20 7353 4200

Martin Robinson

Martin Pengelley

Harry Cameron

Presentation to Analysts and InvestorsA presentation to analysts and investors will be held at 09:30 today - London time. The presentation and Q&A will also be accessible via an audio webcast, available on the investor relations section of the EnQuest website at www.enquest.com. A conference call facility will also be available at 09:30 on the following numbers:

Conference call details:

UK: +44 (0) 844 571 8892 or +44 (0) 800 376 7922

International: +44 (0) 207 192 8000

Confirmation Code: EnQuest

Notes to editors

This announcement has been determined to contain inside information.

Identity of the person making this notification: Stefan Ricketts, Company Secretary

ENQUEST

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

EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm. Its UK operated assets include Thistle/Deveron, Heather/Broom, the Dons area, Magnus, the Greater Kittiwake Area, Scolty/Crathes, Alma/Galia, Kraken and the Sullom Voe Terminal; EnQuest also has an interest in the non-operated Alba oil field. At the end of June 2019, EnQuest had interests in 17 UK production licences and was the operator of 15 of these licences. EnQuest's interests in Malaysia include the PM8/Seligi Production Sharing Contract and the Tanjong Baram Risk Services Contract, both of which the Group operates.

Forward-looking statements: This announcement may contain certain forward-looking statements with respect to EnQuest's expectation 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 on as a guide to future performance. 

FINANCIAL REVIEW

Financial Overview

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

Comparative figures for the Statement of Comprehensive Income relate to the period ended 30 June 2018 and the Balance Sheet as at 31 December 2018.

Production on a working interest basis increased by 27.0% to 68,548 Boepd, compared to 53,990 Boepd in the first half of 2018.

Revenue for the six months ended 30 June 2019 was $858.2 million, 56.5% higher than the comparative six month period (2018: $548.3 million).

The Group's operating expenditures of $248.4 million were 12.6% higher than the comparative period (2018: $220.6 million) reflecting the acquisition of the additional equity interest in Magnus. Unit operating costs decreased by 11.1% to $20.1/Boe (2018: $22.6/Boe).

EBITDA for the six months ended 30 June 2019 was $525.9 million, up 68.6% than the comparative period (2018: $311.9 million).

EnQuest's net debt decreased by $136.6 million from $1,774.5 million at the end of 2018 to $1,637.9 million at 30 June 2019. Net debt at 30 June 2019 includes $132.5 million of inception to date interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing ('PIK'), compared to $132.0 million at 31 December 2018. Excluding the PIK capitalised in 2019, net debt reduced by $137.1 million.

(i) Stated excluding accrued interest, accounting adjustment on adoption of IFRS 9 Financial Instruments and the net-off of unamortised fees. Includes $117.4 million of PIK (2018: $117.5 million)

(ii) Stated excluding accrued interest. Includes $15.1 million of facility PIK (2018: $14.4 million)

(iii) Stated excluding accrued interest and the net-off of unamortised fees. Includes $7.4 million of capitalised interest (2018: $3.5 million)

Having repaid $70.0 million of the 2019 RCF amortisation in 2018, during the six months ended 30 June 2019 the Group repaid a further $160.0 million. An additional voluntary prepayment of $10.0 million was made during July 2019. The remaining $35.0 million of the scheduled amortisation reduction under the facility is due in October.

UK corporate tax losses and allowances at 30 June 2019 decreased to $3,090.4 million (2018: $3,225.3 million). In the current environment, no material corporation tax or supplementary corporation tax is expected to be paid on UK operational activities for the foreseeable future. The Group paid cash corporate income tax on the Malaysian assets which will continue throughout the life of the Production Sharing Contract.

Income Statement

Production and revenue

Production on a working interest basis increased by 27.0% to 68,548 Boepd, compared to 53,990 Boepd in the first half of 2018. This increase primarily reflects the impact of the Group's acquisition of additional equity interest in Magnus.

On average, market prices for crude oil in the first half of 2019 were lower than in the same period in 2018. The Group's blended average realised oil price excluding the impacts of hedging was $65.4/bbl for the six months ended 30 June 2019, 4.0% lower than the comparative period (2018: $68.1/bbl). Revenue is predominantly derived from crude oil sales, which for the six months ended 30 June 2019 totalled $761.9 million, 25.1% higher than the comparative period (2018: $608.9 million) reflecting higher production. Revenue from the sale of condensate and gas in the period was $79.9 million (2018: $10.7 million) driven by additional gas sales, including purchased gas not required for injection activities, at Magnus. Tariff and other income generated $8.9 million (2018: $6.0 million). The Group's commodity hedges and other oil derivatives contributed $7.6 million of realised gains (2018: losses of $77.3 million), including a gain of $4.7 million of non-cash amortisation of option premiums (2018: loss of $16.0 million).

Cost of sales

Cost of sales were $588.3 million for the six months ended 30 June 2019, 31.5% higher than the comparative period (2018: $447.5 million). Operating costs increased by $27.8 million, reflecting the acquisition of the additional equity interest in Magnus. The Group's average unit operating cost has decreased by 11.1% to $20.1/Boe.

Change in lifting position and inventory was a charge of $29.4 million for the six months ended 30 June 2019 (2018: gain of $3.3 million), mainly due to the reduction in the Group's net underlift position.

Depletion expense of $250.4 million was 15.7% higher than the comparative period (2018: $216.5 million), primarily reflecting the contribution to production from Magnus in 2019.

Other cost of sales of $60.1 million was higher than the comparative period (2018: $13.7 million) and primarily reflects the cost of additional Magnus-related third-party gas purchases not required for injection activities.

General and administrative expenses

General and administrative expenses decreased to $5.1 million for the six months ended 30 June 2019 (2018: $7.0 million), mainly reflecting the Group's personnel and property costs.

Other income and expenses

Net other expenses of $0.3 million (2018: net income of $11.4 million) is primarily comprised of net foreign exchange gains, which relate to the revaluation of Sterling denominated amounts in the balance sheet.

Finance costs and income

Finance costs of $106.8 million were 12.5% lower than the comparative period (2018: $122.0 million). The charges include $69.7 million of interest payable on loans and borrowings and bonds (2018: $79.6 million), $26.8 million of finance charges related to lease liabilities (2018: $28.5 million), $7.0 million unwinding of discount on provisions and liabilities (2018: $6.6 million), together with other facility fees such as commitment fees, and the amortisation of bond fees. During the six months ended 30 June 2019, finance costs were reduced by interest capitalisation of $1.1 million in respect of the Dunlin bypass pipeline project.

Finance income was a total of $1.1 million for the six months ended 30 June 2019 (2018: $1.4 million).

Taxation

The tax charge for the six months ended 30 June 2019 is $36.2 million (2018: $23.0 million tax credit).

Remeasurements and exceptional items

Remeasurements and exceptional items resulting in a net loss of $120.0 million before tax have been disclosed separately for the six months ended 30 June 2019 (2018: gain of $34.5 million).

Revenue included unrealised losses of $42.9 million in respect of the mark to market movement on the Group's commodity contracts (2018: unrealised gains of $2.5 million). Other items include a charge to the statement of comprehensive income as a result of an increase in fair value relating to the contingent consideration on the 75% acquisition of Magnus and associated infrastructure of $26.9 million, which reflects the Group's expectations of continued strong performance at Magnus, $28.1 million unwinding of discount on the end 2018 contingent consideration balance and the provision for settlement of the historical KUFPEC claim of $15.6 million (2018: fair value adjustment of the discounted purchase option valuation for Magnus and associated infrastructure assets of $41.8 million).

A tax credit of $41.7 million (2018: credit of $1.2 million) has been presented as exceptional, representing the tax impact of the above items.

Cash flow and liquidity

Net debt at 30 June 2019 amounted to $1,637.9 million, including PIK of $132.5 million, compared with net debt of $1,774.5 million, including PIK of $132.0 million, at 31 December 2018. The Group has remained in compliance with financial covenants under its debt facilities throughout the six month period. The movement in net debt was as follows:

The Group's reported net cash flows from operating activities for the six months ended 30 June 2019 were $409.0 million, 20.6% up compared to the comparative period (2018: $339.1 million). The main drivers for this increase are the impact of higher production and a higher realised oil price.

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

Cash capital expenditure primarily relates to Kraken activities and the Dunlin bypass pipeline project.

Balance Sheet

The Group's total asset value has decreased by $118.3 million to $5,543.6 million at 30 June 2019 (31 December 2018: $5,661.9 million), mainly due to depletion of oil and gas assets offset by the recognition of the IFRS 16 Leases right-of-use assets. Net current liabilities have decreased by $9.0 million to $292.2 million as at 30 June 2019 (31 December 2018: $301.2 million). Included in the Group's net current liabilities are $159.7 million of estimated future obligations where settlement is ring-fenced to the financial performance at Kraken and Magnus (31 December 2018: $135.4 million).

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

Property, plant and equipment has decreased to $4,282.1 million at 30 June 2019 from $4,349.9 million at 31 December 2018. This decrease is explained by depletion and depreciation charges of $255.4 million largely offset by capital additions of $113.4 million and initial recognition of IFRS 16 Leases right-of-use assets of $79.5 million. Capital additions are set out in the table below:

Intangible oil and gas assets

Intangible oil and gas assets slightly increased by $1.4 million to $53.2 million at 30 June 2019 (31 December 2018: $51.8 million).

Trade and other receivables

Trade and other receivables have increased by $52.9 million to $328.7 million at 30 June 2019 compared to $275.8 million at 31 December 2018. The increase relates mainly to the timing of crude oil sales, partially offset by other working capital movements.

Cash and net debt

The Group had $180.1 million of cash and cash equivalents and $1,637.9 million of net debt, including PIK of $132.5 million, at 30 June 2019 (31 December 2018: $240.6 million cash and cash equivalents and $1,774.5 million of net debt, including PIK of $132.0 million). Net debt comprises the following liabilities:

·; $218.0 million in respect of the Group's £155 million retail bond, including $21.3 million of interest capitalised as an amount payable in kind ('PIK');

·; $746.1 million in respect of the Group's high yield bond, including $96.1 million of capitalised PIK;

·; $640.1 million in respect of the credit facility, comprising amounts drawn down of $625.0 million and capitalised PIK of $15.1 million;

·; $165.0 million in respect of the Oz Management facility, comprising amounts drawn down of $157.6 million and capitalised interest of $7.4 million;

·; $31.7 million outstanding under the Tanjong Baram project finance facility; and

·; $17.1 million relating to the SVT Working Capital Facility.

On 1 January 2018, the Group adopted the new accounting standard IFRS 9 Financial Instruments. This resulted in an accounting adjustment to opening reserves of $38.1 million; $22.7 million against the retail bond and $15.4 million against the high yield bond. At 1 January 2019 this adjustment was updated, resulting in an accounting adjustment that increased opening reserves by $16.6 million; $18.9 million against the retail bond, $14.5 million against the high yield bond and an offsetting $16.6 million against the interest accrual (see note 17).

Provisions

The Group's decommissioning provision increased by $4.7 million to $676.4 million at 30 June 2019 (31 December 2018: $671.7 million). The movement is driven primarily by interest unwinding of $6.7 million and additions of $4.6 million offset by utilisation of $6.0 million.

Income tax

The Group has a corporation tax liability at 30 June 2019 of $12.3 million, compared to $15.3 million at 31 December 2018. This primarily represents tax payable in relation to the activity in Malaysia.

Deferred tax

The Group's net deferred tax asset has increased from $258.9 million at 31 December 2018 to $277.6 million at 30 June 2019. Total UK tax losses and allowances carried forward at the half year amount to $3,090.4 million (31 December 2018: $3,225.3 million).

Trade and other payables

Trade and other payables of $464.5 million at 30 June 2019 decreased from $502.0 million at 31 December 2018. $447.3 million are payable within one year (31 December 2018: $483.8 million) and $17.2 million are payable after more than one year (31 December 2018: $18.2 million). The movement reflects the timing of settlement of previously deferred invoices and the adjustment in relation to IFRS 9 Financial Instruments (see note 17).

Financial Risk Management

Oil price

The Group is exposed to the impact of changes in Brent crude oil prices on its revenue and profits. EnQuest's policy is to manage the impact of commodity prices to protect against volatility and allow availability of cash flow for reinvestment in capital programmes that are driving business growth.

During the six months ended 30 June 2019, commodity derivatives generated a total loss of $38.4 million, with revenue and other operating income including a realised gain of $7.6 million. The losses were mostly in respect of open call options and the amortisation of premiums on calls.

Foreign exchange

EnQuest's functional currency is US Dollars. Foreign currency risk arises on purchases and the translation of assets and liabilities denominated in currencies other than US Dollars. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of the non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged.

EnQuest continually reviews its currency exposures and, when appropriate, looks at opportunities to enter into foreign exchange hedging contracts. During the six months ended 30 June 2019, these contracts resulted an unrealised loss of $2.0 million recognised in the income statement.

Surplus cash balances are deposited as cash collateral against in-place letters of credit as a way of reducing interest costs. Otherwise, cash balances can be invested in short-term bank deposits and AAA-rated liquidity funds, subject to Board-approved limits and with a view to minimising counterparty credit risks.

Going concern

The Group closely monitors and manages its funding position and liquidity risk throughout the year, including monitoring forecast covenant results, to ensure that it has access to sufficient funds to meet forecast cash requirements. Cash forecasts are regularly produced and sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and project timing and costs. These forecasts and sensitivity analyses allow management to mitigate liquidity or covenant compliance risks in a timely manner. Management also continues to take action to implement cost saving programmes to reduce operational expenditure, general and administrative spend and capital expenditure. At 30 June 2019, the Group had total cash and available facilities of $248.5 million, including ring-fenced accounts associated with Magnus, the Oz Management facility and other joint venture accounts totalling $79.1 million.

The Group's forecast ('Base case'), which underpins this assessment, assumes Kraken production rates are in line with the Group's production guidance. The Base case has been updated at the half year for the forward curve and uses an oil price assumption of c.$63.7/bbl from August 2019 and c.$60.9/bbl for 2020. Specifically the Base case has been subjected to stress testing by considering the impact of the following plausible downside risks (the 'Downside case'):

·; a 10% discount to the oil price forward curve;

·; a 3.5% decrease in 2019 and a 3% decrease in 2020 production;

·; a 2.5% increase in operating costs except for fixed costs related to the Kraken FPSO; and

·; a 2.5% increase in capital expenditure from 2020 onwards.

Both cases reflect the bank debt amortisation profile due in the going concern period. The Directors consider the Base case and Downside case to be an appropriate basis on which to make their assessment.

The Base case and Downside case indicate that the Company is covenant compliant and able to operate within the headroom of its existing borrowing facilities for 12 months from the date of approval of the Half year Report and Accounts. Should circumstances arise that differ from our 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 enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group can continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing the financial statements.

The Group's risks and uncertainties are substantially unchanged from those disclosed in the Group's Annual Report and Accounts 2018.

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

·; Health, Safety and Environment ('HSE'):

o Oil and gas development, production and exploration activities are complex and HSE risks cover many areas including Major Accident Hazards, personal health and safety, compliance with regulatory requirements, asset integrity issues and potential environmental harm and costs, including those associated with the impacts of climate change.

·; Oil price:

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

·; Production:

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

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

o Climate change could result in more severe weather conditions over time, which could impact asset uptime.

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

o Longer-term production is threatened if low oil prices or low reservoir performance bring forward decommissioning timelines.

·; Project execution and delivery: 

o The Group's success will be partially dependent upon the successful execution and delivery of development projects.

·; Subsurface risk and reserves replacement:

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

·; Financial: 

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

o The Group's term loan and revolving credit facility contains certain financial covenants (based on the ratio of indebtedness incurred under the term loan and revolving facility to EBITDA, finance charges to EBITDA and a requirement for liquidity testing) and an amortisation schedule. 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.

o Further information is contained in the going concern paragraph in the Financial Review.

·; Human resources: 

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

·; Reputation:

o The reputational and commercial exposures to a major offshore incident, including those related to an environmental incident, or non-compliance with applicable law and regulation are significant.

·; Fiscal risk and government take: 

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

·; Joint venture partners: 

o Failure by joint venture parties to fund their obligations.

o Dependence on other parties where the Group is not the operator.

·; Competition: 

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

·; Portfolio concentration:

o The Group's assets are 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 aging pipelines and terminals), political/fiscal changes and oil price movements.

·; International business:

o The Group's international business is subject to the same risks as the UK business (e.g. HSE, production and project execution); however, there are additional risks that the Group faces including security of staff and assets, political, foreign exchange and currency control, taxation, legal and regulatory, cultural and language barriers and corruption.

·; IT security and resilience: 

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

We urge you to consider carefully the risks above, full details of which are contained in the Group's Annual Report and Accounts 2018.

HALF YEAR GROUP STATEMENT OF COMPREHENSIVE INCOME

For the six months ended 30 June 2019

(i) Restated to reflect the impact of the October 2018 rights issue

GROUP BALANCE SHEET

At 30 June 2019

GROUP STATEMENT OF CHANGES IN EQUITY

For the six months ended 30 June 2019

GROUP STATEMENT OF CASH FLOWS

For the six months ended 30 June 2019

NOTES TO THE HALF YEAR CONDENSED FINANCIAL STATEMENTS

For the period ended 30 June 2019

1. Corporate information

EnQuest PLC ('EnQuest' or 'the Company') is a limited liability Company incorporated and registered in England and is listed on the London Stock Exchange and on the Stockholm NASDAQ OMX.

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

The Group's half year condensed financial statements for the six months ended 30 June 2019 were authorised for issue in accordance with a resolution of the Board of Directors on 4 September 2019.

2. Summary of significant accounting policies

Basis of preparation

The interim condensed consolidated financial statements of the Group for the six months ended 30 June 2019 have been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted by the European Union. The presentation currency of the Group financial information is United States 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 2018.

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

Consolidated statutory accounts for the year ended 31 December 2018, on which the auditors 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 11.

Accounting policies

The accounting policies adopted in the preparation of the interim condensed financial statements for the six months ended 30 June 2019 are materially consistent with those followed in the preparation of the Group's financial statements for the year ended 31 December 2018, except for the adoption of new standards effective as of 1 January 2019. Any other standard, interpretation or amendment that was issued but not yet effective has not been adopted by the Group.

New and amended standards adopted by the Group

The following new standard became applicable for the current reporting period and the Group had to change its accounting policies as a result of the adoption:

·; IFRS 16 Lease Accounting

The impact of the adoption of this standard and the new accounting policies are disclosed in note 17. A number of other new standards are effective from 1 January 2019 but they do not have a material effect on the Group's financial statements.

3. Segment information

Segment information for the six month period is as follows:

Adjustments and eliminations mainly includes other income and costs, and gains and losses on derivatives which are not allocated to individual segments as the underlying instruments are managed on a Group basis. Inter-segment revenues are eliminated within the relevant segment.

Reconciliation of profit:

4. Remeasurements and exceptional items

i. Fair value remeasurements include unrealised mark to market movements on derivative contracts and other financial instruments. It also includes the impact of recycling realised gains and losses (including option premiums) out of 'Remeasurements and exceptional items' and into 'Business performance' profit or loss. Other expenses include the fair value adjustment relating to the contingent consideration on the 75% acquisition of Magnus and associated infrastructure of $26.9 million (note 14) (2018: Other income includes the fair value adjustment of the discounted purchase option valuation for Magnus and associated infrastructure of $41.8 million and finance costs include the fair value adjustment relating to the contingent consideration on the 25% acquisition of Magnus and associated infrastructure of $6.3 million).

ii. Impairments and write offs include an impairment of tangible oil and gas assets totalling $3.2 million (2018: $6.6 million).

iii. Other includes other items of income and expense which, because of the nature or expected infrequency of the events giving rise to them, merit separate presentation to allow shareholders to understand better the elements of financial performance in the period so as to facilitate comparison with prior periods and to better assess trends in financial performance. Net other expenses mainly includes the provision for settlement of the historical KUFPEC claim of $15.6 million (note 14). Finance costs reflects the unwinding of contingent consideration in relation to the acquisition of Magnus and associated infrastructure of $28.1 million (note 14) (2018: Net other income mainly relates to release of a $5.3 million provision associated with an exploration licence relinquished in the period).

iv. Other tax exceptional items include the tax effect of the derecognition of current period tax losses (2018: $6.9 million of current period tax losses).

5. Revenue and other operating income

The Group's operations and main revenue streams are those described in the last annual financial statements.The Group's revenue is mainly derived from contracts with customers, except for amounts related to derivative contracts.

(i) Unrealised gains and losses on oil derivative contracts which are held for trading are disclosed as exceptional items in the income statement (see note 4)

Revenue is primarily derived within Europe on short-term contracts which are, on average, settled between 15 - 30 days post control gained by the customer.

Revenue derived from the sale of crude oil, gas and condensate is recognised as goods transferred at a point in time when control is gained by the customer on collection or delivery. The sale of oil is subject to market prices. The Group manages this risk through the use of oil derivative contracts. Revenue derived from tariff and rental income is recognised as the service is transferred over time.

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.

Basic and diluted earnings per share are calculated as follows:

(i) Restated to reflect the impact of the October 2018 rights issue

7. Property, plant and equipment

(i) Following the adoption of IFRS 16 Leases, the Kraken FPSO lease asset has been reclassified to right-of-use assets

8. Intangible oil and gas assets

9. Share capital and premium

The share capital of the Company as at 30 June 2019 was $118.2 million (31 December 2018: $118.2 million) comprising 1,695,418,806 Ordinary shares of £0.05 each (31 December 2018: 1,694,406,148) and share premium of $227.1 million (31 December 2018: $227.1 million).

10. Loans and borrowings

The Group's loans are debt instruments carried at amortised cost as follows:

(i) Includes 'Payment in Kind' interest totalling $15.1 million (31 December 2018: $14.4 million)

(ii) Includes capitalised interest totalling $7.4 million (31 December 2018: $3.5 million)

11. Bonds

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

(i) Includes 'Payment in Kind' interest totalling $96.1 million (31 December 2018: $96.1 million)

The total carrying value of the bond as at 30 June 2019 is $754.5 million. This includes bond principal of $746.1 million, bond interest accrual of $10.9 million and liability for the IFRS 9 Financial Instruments loss on modification of $3.0 million less unamortised fees of $5.5 million (2018: $765.1 million. Includes bond principal of $746.1 million, bond interest accrual of $11.0 million and liability for the IFRS 9 Financial Instruments loss on modification of $14.5 million less unamortised fees of $6.5 million)

(ii) Includes 'Payment in Kind' interest totalling $21.3 million (31 December 2018: $21.5 million)

The total carrying value of the bond as at 30 June 2019 is $235.0 million. This includes bond principal of $218.0 million, bond interest accrual of $5.6 million and liability for the IFRS 9 Financial Instruments loss on modification of $12.7 million less unamortised fees of $1.3 million (2018: $242.0 million. This includes bond principal of $218.9 million, bond interest accrual of $5.8 million and liability for the IFRS 9 Financial Instruments loss on modification of $18.9 million less unamortised fees of $1.6 million)

12. Other financial assets and financial liabilities

(a) Summary

The fair value measurements of the financial instruments (excluding Level 1 investments) held by the Group have been derived based on observable market inputs (as characterised within Level 2 of the fair value hierarchy under IFRS 13). There have been no changes to classifications from 31 December 2018.

(b) Commodity contracts

The Group uses put and call options and swap contracts to manage its exposure to the oil price.

During the six months ended 30 June 2019, no commodity derivatives were designated as effective oil hedges.

Commodity derivative are designated at fair value through profit and loss ('FVTPL'), and gains and losses on these contracts are recognised as a component of revenue. These contracts typically include bought and sold call options, bought put options and commodity swap contracts.

During the six months ended 30 June 2019, losses totalling $34.2 million (2018: losses of $71.7 million) were recognised in respect of commodity contracts designated as FVTPL. This included realised gains totalling $8.7 million (2018: losses of $74.2 million) on contracts that matured during the period, and mark to market losses totalling $42.9 million (2018: gains of $2.5 million). Of the realised amounts recognised during the period, $4.7 million (2018: $16.0 million) was realised in Business performance revenue in respect of the amortisation of premiums paid on sale of these options. The premiums received and paid are amortised into Business performance revenue over the life of the option.

In October 2017, the Group entered into an 18-month collar structure for $80 million, which expired in April 2019. The collar included 18 separate call options and 18 separate put options, subject to a floor of $45/bbl and a cap of approximately $64/bbl. Of the amounts recognised in respect to commodity contracts, losses totalling $1.1 million were realised on the collar (2018: losses totalling $3.1 million) and open market to market gains of $nil million were recognised within unrealised revenue (2018: $0.4 million).

(c) Foreign currency contracts

The Group enters into a variety of foreign currency contracts, including Sterling, Euros, Swedish Krona, Norwegian Krone and United Arab Emirates Dirhams. During the six months ended 30 June 2019, these contracts resulted an unrealised loss of $2.0 million recognised in the income statement (2018: loss of $0.4 million).

(d) Income statement impact

The income/(expense) recognised for commodity, currency and interest rate derivatives are as follows:

(e) Other receivables and liabilities

Other receivables

In August 2016, EnQuest agreed with Armada Kraken PTE Ltd ('BUMI') that BUMI would refund $65 million (EnQuest's share being $45.8 million) of a $100.0 million lease prepayment made in 2014 for the FPSO for the Kraken field.This refund is receivable during 2019 and onwards. Included within other receivables at 30 June 2019 is an amount of $11.2 million representing the discounted value of EnQuest's share of these repayments (31 December 2018:$15.5 million). A total of $4.8 million was collected during the period. Unwinding of discount of $0.5 million is included within finance income in the six months ended 30 June 2019 (30 June 2018: $0.7 million).

There were no other liabilities at 30 June 2019 and 31 December 2018.

13. Fair value measurement

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

(i) Valued using readily available information in the public markets and quotations provided by brokers and price index developers

(ii) Valued by the counterparties, with the valuations reviewed internally and corroborated with market data

There have been no transfers between Level 1 and Level 2 during the period (2018: no transfers).

14. Provisions

Decommissioning provision

An additional provision of $4.6 million was recognised in relation to the development carried out on the Dunlin bypass and Scolty/Crathes pipeline projects during the period. No changes to the underlying cost estimates have occurred, with the changes in estimate relating to the impact of exchange rates on the underlying Sterling and Malaysian Ringgit cost estimates.

Cost recovery provision

As part of the KUFPEC farm-in agreement, a cost recovery protection mechanism was agreed with KUFPEC to enable KUFPEC to recoup its investment to the date of first production. If on 1 January 2017, KUFPEC's costs to first production had not been recovered or deemed to have been recovered, EnQuest would pay KUFPEC an additional 20% share of net revenue. This additional revenue is to be paid until the capital costs to first production have been recovered. As at 30 June 2019, there was no further cost recovery, as per the agreement, and the provision was released against the corresponding balance in property, plant and equipment..