Enquest Regulatory News (ENQ)

ENQUEST PLC, 7 September 2017. Results for the 6 months ended 30 June 2017*. 

Highlights and outlook

* Unless otherwise stated, all figures are on a business performance basis and are in US dollars.

** Including realised income of $0.3 million (2016: $128.1 million) associated with EnQuest's oil price hedges. ***EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation, foreign exchange movements and the realised gains/loss on foreign currency derivatives related to capital expenditure. The prior year EBITDA has been restated on a comparable basis by adding back realised losses on foreign currency derivatives related to capital expenditure of $9.4 million.   

EnQuest CEO Amjad Bseisu said:

"EnQuest was pleased to bring the Kraken field onstream on 23 June 2017, with substantially reduced capex, assisted by the excellent delivery of the drilling and subsea programmes; we expect the first cargo load of oil to be lifted from the Kraken FPSO in the next few days.  Kraken remains on course to achieve plateau production of approximately 50,000 Boepd gross in H1 2018, driving a material increase in EnQuest's production in 2018 and beyond. EnQuest expects to deliver the targeted reductions in capital expenditure post Kraken start up and to complete the Magnus/SVT acquisition before the year end. Deleveraging the balance sheet remains a key post Kraken start up objective."

Financial review of H1 2017 

Production statistics

H1 2017 production and development performance and outlook by asset:

1 Net production since first oil on 23 June, averaged over the six months to end June 2017

UK North Sea

Northern North Sea production

The ongoing Thistle/Deveron programme to increase the reliability of water injection continues to have a positive impact and plant uptime is also improving. At the Don fields, well performance was above expectations at Don Southwest, with high levels of production efficiency across the Don fields. Production improving chemical treatments have been completed at West Don and are underway at Don Southwest. 2017 water injection issues at Heather/Broom have impacted production year on year, offset by high levels of production efficiency.

Central North Sea Production

The work programme in the Greater Kittiwake Area ('GKA') and Scolty/Crathes for 2017 continues to be focused on optimising production across the assets. Good production has been delivered from the GKA fields, with high levels of plant uptime and production efficiency. Production rates on Scolty/Crathes have been constrained due to wax build up in the pipeline. Chemical treatments have been carried out which have allowed production to continue at reduced rates. Further work is ongoing to finalise longer term solutions. Evaluation of the potential from the Eagle discovery is ongoing; Dana Petroleum has confirmed its intention to withdraw from this discovery.

At Alma/Galia, the final phases of the optimisation projects for power, produced water and sea water injection on the EnQuest Producer, have all been completed. As expected at the time of EnQuest's full year 2016 results announcement in March, 2017 production from Alma/Galia has been lower than in 2016, given wells have been shut in, production outages in Q1 due to storm damage and natural declines. Discussions continue with the ESP supplier, on rectification plans to address the ongoing pump reliability issues.

The Kraken development

First oil from Kraken was delivered on 23 June 2017. To date, the four wells from drill centre 1 ('DC1') and two wells out of the three wells from drill centre two ('DC2'), have produced at initial gross rates above expectations and with stabilised flow rates which confirm the Field Development Plan. The sum of DC1 maximum individually tested well rates have been approximately 24,000 Bopd, with stabilised combined well rates at approximately 15,000 Bopd. One DC2 well has been tested at a rate above 10,000 Bopd, demonstrating excellent reservoir properties and completion efficiency. The proven individual stabilised production rates from the six wells tested so far aggregate to around 30,000 bopd, representing c.60% of the c,50,000,bopd gross plateau production. Injection wells have also surpassed expectations. The hydraulic submersible pumps, subsea production system and turret have all performed as expected.

Commissioning of the FPSO vessel topsides equipment continues and, despite good well deliverability, has been constraining production so far. Whilst in Q3 2017, volumes are behind forecast as equipment is commissioned, we expect operational uptime to improve accordingly and to deliver plateau production of approximately 50,000 Bopd gross in H1 2018. Whilst production is constrained, charter rates are reduced in accordance with production levels.

DC3 wells are now due to complete in Q4 2017, ahead of schedule, further facilitating the achievement of plateau performance in H1 2018.

We expect to achieve a further c.$100 million of capex savings on the project as a result of the drilling of DC3 being completed 3 to 4 months earlier than planned and lower market rates for the remaining subsea campaign. Full cycle gross project capex is now estimated to be c.$2.4 billion, 25% down on the original sanctioned cost of $3.2 billion. 

Alba (non-operated) 

Production from Alba benefitted from the A49 well coming back online in March.

PM8/Seligi

EnQuest continues to invest in low cost well work and facility projects to improve production efficiency, including gas compression train refurbishments. In addition, robust inspection and refurbishment campaigns on platform topsides and structures support ongoing safe operations.

Longer term, EnQuest will extend field life through further investment in idle well restoration, facility improvements and upgrades, well workovers, new drilling and secondary recovery projects to increase ultimate recovery. Significant progress is being made in 2017 on technical studies to better define the next phase of these projects.

Tanjong Baram

Focus remains on steady, safe and low cost operations. Tanjong Baram field has produced with an excellent operational uptime in 2017.

Ends

For further information please contact:

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

Amjad Bseisu (Chief Executive)

Jonathan Swinney (Chief Financial Officer)

Michael Waring (Head of Communications & Investor Relations)

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

Martin Robinson

Martin Pengelley

Presentation to Analysts and Investors

A 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 from 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) 20 3427 1900 

USA: +1646 254 3360 

Confirmation Code: EnQuest

Notes to editors

ENQUEST

EnQuest is one of the largest UK independent producers in the UK North Sea. EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm. Its operated assets include Thistle/Deveron, Heather/ Broom, the Dons area, the Greater Kittiwake Area, Scolty/Crathes Alma/Galia and Kraken; EnQuest also has an interest in the non-operated Alba producing oil field. At the end of June 2017, EnQuest had interests in 24 UK production licences and was the operator of 22 of these licences.

EnQuest believes that the UKCS represents a significant hydrocarbon basin, which continues to benefit from an extensive installed infrastructure base and skilled labour. EnQuest believes that its assets offer material organic growth opportunities, driven by exploitation of current infrastructure on the UKCS and the development of low risk near field opportunities.

EnQuest is replicating its model in the UKCS by targeting previously underdeveloped assets in a small number of other maturing regions; complementing its operations and utilising its deep skills in the UK North Sea. In which context, EnQuest has interests in Malaysia where its operated assets include the PM8/Seligi Production Sharing Contract and the Tanjong Baram Risk Services Contract.

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 presentation should be construed as a profit forecast. Past share performance cannot be relied on as a guide to future performance.

Glossary

DC Drill centre

ESP Electrical submersible pump

FDP Field development plan

FPSO Floating production, storage and offloading vessel

GKA Greater Kittiwake AreaSVT Sullom Voe Terminal

FINANCIAL REVIEW

Financial Overview

Production, on a working interest basis, decreased by 13% to 37,015 Boepd, compared to 42,520 Boepd in the first half of 2016. This included six months of production from Scolty Crathes, contributing 3,362 Boepd, which did not commence production until the second half of 2016.

Reflecting this reduction in production, EnQuest's unit operating costs increased by 9% to $25 per barrel.

(i) Realised gains/losses on FX derivatives are recorded within cost of sales. Where the derivative hedges capital expenditure the gain/loss is added back when calculating EBITDA in order to reflect the underlying result of operating activities. Prior period EBITDA has been restated on a comparable basis by adding back realised losses on FX derivatives related to capital expenditure of $4.6 million

EBITDA for the six months ended 30 June 2017 was $151.0 million compared with $247.5 million during the six months ended 30 June 2016. The lower EBITDA is mainly due to the reduced contribution from the Group's commodity hedge portfolio, which contributed $0.3 million (2016: $128.1 million) and the impact of reduced production, partially offset by the higher average realised prices experienced in the first half of 2017 as compared to the same period in 2016.

Reflecting the ongoing investments EnQuest has made in its assets, notably Kraken, EnQuest's net debt has increased from $1.80 billion at the end of 2016 to $1.92 billion at 30 June 2017. This includes $56.7 million of interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing.

1 Stated excluding accrued interest and excluding the net-off of unamortised fees.

There are no significant debt maturities until April 2018, when amortisation of the RCF is due to commence.

As a result of the continued capital investment, UK corporate tax losses at the end of the half-year increased to approximately $3.18 billion. In the current environment, no material corporation tax or supplementary corporation tax is expected to be paid on UK operational activities. 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 levels, on a working interest basis, averaged 37,015 Boepd in the first half of 2017 compared with 42,520 Boepd in 2016. The reduction reflects the impact of natural declines, together with the well performance issues at Alma Galia, partially offset by six months of production from Scolty Crathes which achieved first oil during H2 2016 and contributed 3,362 Boepd in the first half of 2017.

On average, oil prices in the first half of 2017 were higher than in the same period last year. The Group's blended average realised price per barrel of oil sold excluding hedging was $52 for the six months ended 30 June 2017, above the $41 per barrel received during the first half of 2016, reflecting the recovery in prices since the prior six month period. Revenue is predominantly derived from crude oil sales and for the six months ended 30 June 2017 crude oil sales totalled $286.8 million compared with $256.5 million for the comparative period in 2016. The increase in revenue was due to the higher oil price, offset partially by the lower production. Revenue from the sale of condensate and gas was $0.4 million (H1 2016: $0.5 million).

The Group's commodity hedges and other oil derivatives generated $0.3 million of realised income (2016: $128.1 million). This includes $10.5 million of non-cash amortisation of option premiums (H1 2016: $15.2 million). A total unrealised gain of $47.6 million was recognised within exceptional items in respect of the mark to market movement on the Group's commodity contracts (H1 2016: unrealised loss of $9.1m).

Cost of sales

Cost of sales, on a business performance basis, was as follows:

Business performance cost of sales were $248.6 million for the six months ended 30 June 2017 compared with $273.6 million for the six months ended 30 June 2016. Operating costs decreased by $7.7 million, primarily due to the benefit of a weaker sterling exchange rate, partially offset by operating costs on Scolty and Crathes which were not producing in the first half of 2016. On a per barrel basis, the Group's average operating cost per barrel has increased by 9% to $25 per barrel, primarily due to the 13% reduction in production volumes.

Change in the lifting position and inventory resulted in a $23.7 million credit to cost of sales, reflecting the unwind of the overlift balance that had accrued at 31 December 2016, primarily on Thistle and GKA, partially offset by the unwind of underlift at Alma Galia and the build-up of an overlift at Scolty Crathes.

Depletion expense of $94.4 million was $34.1 million lower than the prior period, reflecting reduced production in the first half of 2017 as compared to the same period last year.

Other cost of sales, which principally include the supplemental payment due on profit oil in Malaysia, increased by $3.2 million, reflecting the impact of higher oil prices on the supplemental payment.

General and administrative expenses

General and administrative expenses was a total of $1.3 million for the six months ended 30 June 2017, compared with a charge of $5.4 million for the same period last year, reflecting the Group's ongoing efforts to reduce costs.

Other income and expenses

Other expenses of $11.3 million (30 June 2016: income of $37.3 million) is primarily comprised of net foreign exchange losses, which relate to the revaluation of sterling denominated amounts in the balance sheet following the strengthening of the pound against the dollar. The prior half included foreign exchange gains of $37.3 million, reflecting a weakening of sterling.

Finance costs

Finance costs of $36.3 million (30 June 2016: $66.8 million) includes principally $65.7 million of bond and loan interest payable (30 June 2016: $52.0 million), offset by the capitalisation of $42.3 million of interest payable on borrowing costs against Kraken (30 June 2016: $23.1 million). The balance includes the unwind of decommissioning and other provisions ($6.6 million), together with other facility fees such as commitment fees, and the amortisation of bond fees. The prior year comparative also included $20.1 million of finance costs related to the amortisation of put option premium related to the Group's oil hedge portfolio. No corresponding charge existed in the current half-year period as no put options had been used to hedge 2017 production.

Finance income

Finance income of $1.4 million (30 June 2017: $0.5 million) includes $1.0 million from the unwind of the discount on the receivable from BUMI for the partial refund of the lease prepayment.

Taxation 

The tax credit for the six months ended 30 June 2017 of $25.0 million (30 June 2016: $56.9 million tax credit), excluding exceptional items, is mainly due to an increase in the Ring Fence Expenditure Supplement ('RFES') on UK activities. 

Remeasurements and exceptional items

Exceptional items resulting in a net loss of $20.0 million before tax have been disclosed separately for the six months ended 30 June 2017 (30 June 2016: loss of $8.5 million). These include tangible oil & gas impairments arising from the decline in the oil price totalling $79.6 million, unrealised gains on commodity and foreign currency derivative contracts of $63.2 million, a $4.0 million charge arising from the cancellation of a crude oil marketing contract, and a $1.3 million gain from the disposal of Ascent Resources loan notes.

A tax credit of $25.7 million (30 June 2016: credit of $19.5 million) has been presented as exceptional, representing the tax impact of the above items, together with a net write-back of $6.7 million of tax losses which had been previously impaired, and a credit of $13.9 million for an adjustment to the level of non-qualifying expenditure capitalised on the balance sheet.

Cash flow and liquidity

The Group's reported operating cash flows for the six months ended 30 June 2017 was $150.6 million compared with $170.2 million for the same period last year. The main driver for this reduction in operating cash flows is the reduced contribution from commodity hedging, where total cashflows received in the first half of 2017 were $19.1 million as compared to $131.4 million for the first half of 2016. This reduced cash flow was partially offset by the impact of higher oil prices on revenue, and reduced operating, and general and administrative expenses.

Net debt at 30 June 2017 amounted to $1,922.3 million compared with net debt of $1,796.5 million at 31 December 2016. The movement in net debt was as follows:

It is anticipated that the underlying effective tax rate for 2017 will be below the UK statutory tax rate of 40%, excluding one-off exceptional tax items, due to UK tax reliefs and profits charged to tax at a lower rate in Malaysia. In the current environment and with the investment in the North Sea, the Group does not expect a material cash outflow for UK corporation tax on operational activities. This is due to the benefits from tax deductible first year capital allowances in the UK, available investment allowances and accumulated tax losses which are largely attributable to the Group's capital investment programme to date. 

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

Kraken was the key significant capital project undertaken during the six months ended 30 June 2017, together with settlement of deferred invoices in respect of Alma Galia, Eagle and Scolty/Crathes.

The Group has remained in compliance with financial covenants under its debt facilities throughout the period and managing ongoing compliance remains a priority. Where necessary or appropriate, the Group would seek waivers and/or consents.

Balance Sheet

The Group's total asset value has increased by $754.6 million to $4,682.2 million at 30 June 2017 (31 December 2016: $3,926.0 million), mainly attributable to the recognition of the Kraken FPSO finance lease asset. Net current liabilities have increased by $138.5 million to $183.6 million as at 30 June 2017 (31 December 2016: $45.1 million). This increase is primarily driven by the reduction in the Groups' cash balances, due to the ongoing capital investments made in the first half of 2017, together with improved working capital).

Property, plant and equipment

Property, plant and equipment ('PP&E') has increased to $3,806.1 million at 30 June 2017 from $2,963.4 million at 31 December 2016.

The increase of $842.7 million is explained by the recognition of the Kraken FPSO finance lease of $772.0 million, additions to PP&E of $189.4 million, an increase of $58.3 million for net changes in estimates for decommissioning and other provisions, offset by depletion and depreciation charges of $97.4 million and non-cash impairments of $79.6 million following the oil price reduction since the year-end.

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

Intangible oil and gas assets

Intangible oil and gas assets increased by $0.9 million to $51.2 million at 30 June 2017.

Trade and other receivables

Trade and other receivables have decreased by $27.5 million to $175.2 million at 30 June 2017 compared with $202.7 million at 31 December 2016. The decrease relates mainly to a $31.0 million reduction in amounts due from partners, following the timing of cash call collection, a $13.5 million reduction in the FPSO lease prepayment following commencement of the lease, partially offset by an increase in trade and hedging receivables reflecting the timing of liftings, and other working capital movements.

Cash and net debt

The Group had $66.9 million of cash and cash equivalents at 30 June 2017 and 1,922.3 million of net debt (31 December 2016: $174.6 million and $1,796.5 million respectively). Net debt comprises the following liabilities:

· $208.6 million in respect of the Group's £155 million retail bond, including $7.1 million of interest capitalised as an amount payable in kind ('PIK Amount');

· $696.5 million in respect of the Group's high-yield bond, including $46.5 million of capitalised PIK interest;

· $1,050.1 million carrying value of the credit facility, comprising amounts drawn down of $1,046.9 million and interest of $3.2 million of capitalised PIK interest;

· $20.0 million outstanding from a trade creditor loan, and

· $14.1 million outstanding under the Tanjong Baram project finance facility.

Provisions

The Group's decommissioning provision increased by $56.1 million to $550.0 million at 30 June 2017 (31 December 2016: $493.9 million). The increase is driven primarily by additions for Kraken of $25.4 million based on drilling and development carried out during the period, and an increase of $27.9 million due to the impact of exchange rates on cost estimates.

Other key movements in provisions during the period include the settlement of the final amount due to Cairn under the carry arrangement, and the payment of $9 million to Centrica pursuant to the GKA acquisition agreement.

Income tax

The Group had no UK corporation tax or supplementary corporation tax liability at 30 June 2017, which remains unchanged from 31 December 2016. The income tax asset at 30 June 2017 represents UK corporation tax receivable in relation to non-upstream activities and the income tax payable is in relation to the activity in Malaysia.

Deferred tax

The Group's net deferred tax asset has increased from $191.7 million at 31 December 2016 to $250.7 million at 30 June 2017. The increase is mainly due to the ring fence expenditure supplement, together with the recognition of $6.7 million of previously derecognised tax losses. Total UK tax losses carried forward at the half year amount to $3,176.3 million.

Trade and other payables

Trade and other payables have decreased to $382.9 million at 30 June 2017, of which $34.0 million is payable after more than one year (2016: $452.9 million, of which $42.6 million was non-current). This reduction mainly reflects the settlement of deferred invoices and a $20.0 million reduction in the overlift position.

Other financial liabilities

Other financial liabilities have reduced by $44.1 million to $19.9 million. The reduction relates to mark to market movements on the Group's commodity derivatives following the weakening of the oil price since year-end.

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 to ensure the availability of cash flow for reinvestment in capital programmes that are driving business growth.

In line with this policy, during 2016 the Group entered into commodity hedging contracts to hedge partially the exposure to fluctuations in the Brent oil price during 2017. This hedging generated cash flows of $14.2 million (including $15.0 million in respect of the settlement of December 2016 hedges) and revenue and other operating income included a loss of $6.3 million during the six months ended 30 June 2017. The amounts were mostly in respect of the settlement of swaps in respect of 4.5 MMbbls, plus the maturity of certain other commodity derivatives. The Group's marketing and trading activities, which are designed to manage price exposures on certain individual cargos, generated $5.0 million of cash, and contributed $6.7 million to revenue and other operating income.

At 30 June 2017, the Group's commodity derivative contracts are comprised of 1.5 MMbbls of swap contracts at an average fixed price of $55.37/bbl.

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.

For the six months ended 30 June 2017, the Group's foreign currency hedging portfolio realised a loss of $7.1 million. Unrealised gains of $15.5 million were also recognised.

At 30 June 2017, the Group had hedged £66.0 million via a chooser contract covering the second half of 2017. Under this contract, the counterparty can elect to sell £66.0 million to EnQuest at an exchange rate of $1.20:£1.0 or purchase 1.5 MMbbls barrels of oil at $60/bbl. The contract had a positive fair value of $5.8 million at 30 June 2017. Based on the current forward curves, it is expected that this contract will settle as a foreign currency trade.

During the six months ended 30 June 2016, the Group entered into a structure covering the first half of 2017. The counterparty could elect to sell £47.5 million to EnQuest at an exchange rate of $1.4:£1.0 or purchase 1,320,000 barrels of oil at $58/bbl. The contract had a negative fair value of $9.3 million at 30 June 2016, and losses of $6.7 million were realised in the first half of 2017 in respect of this contract, with the contract treated as a foreign exchange hedge.

EnQuest continually reviews its currency exposures and when appropriate looks at opportunities to enter into foreign exchange hedging contracts.

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 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 development project timing and costs. These forecasts and sensitivity analysis allow management to mitigate any liquidity or covenant compliance risks in a timely manner.

On 21 November 2016, EnQuest announced a restructuring which comprised the implementation of the RCF Amendments, the Note Amendments, the renewal of the Surety Bond Facilities and the completion of a Placing and Open Offer (collectively "the Restructuring"). The completion of the Restructuring provided the Group with a more stable and sustainable capital structure, reduced cash debt service obligations and greater liquidity. This going concern assessment is prepared on the basis that the Term Loan and Revolving Credit Facility (the "Facility") providers continue to provide access to funding for the duration of the period under review.

Management has also continued to take action to implement cost saving programmes to reduce planned operational expenditure, general and administrative spend and capital expenditure in 2017 and 2018 in light of the continuing lower oil price. At 30 June, the Group had available bank facilities and cash of $213 million.

The 31 December 2016 going concern assessment was based on the then market expectations on oil price and the Group's business plan for production. Since these assumptions have now changed, the assessment has been updated as outlined below. Further, as has been previously disclosed, the Group's ability to return value to shareholders remains highly sensitive to the oil price.

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

· Oil price volatility A material decline in oil and gas prices would adversely affect the Group's operations and financial condition. To mitigate oil price volatility, the Directors hedged 6 MMbbls of 2017 production at an average price of $51 per barrel. 2 MMbbls remain hedged in the second half of 2017 at an average price of $55 per barrel. As further mitigation the Directors, in line with Group policy, will continue to pursue hedging at the appropriate time and price.

· Kraken production

The Kraken field commenced production on 23 June and the production profile within the Group's latest forecast (Base case) assumes specific risking for 2017 and 2018 respectively. To date, the four wells from drill centre 1 ('DC1') and two wells out of the three wells from drill centre two ('DC2'), have produced at initial gross rates above expectations and with stabilised flow rates which confirm the Field Development Plan, demonstrating excellent reservoir properties and completion efficiency. Injection wells have also surpassed expectations. The hydraulic submersible pumps, subsea production system and turret have all performed as expected.

Commissioning of the FPSO vessel topsides equipment continues and, despite good well deliverability, has been constraining production so far. Whilst in Q3 2017, volumes are lower than the Group's initial forecast, we expect operational uptime to improve and to deliver plateau production of approximately 50,000 Bopd gross in H1 2018.

DC3 wells are now due to complete in Q4 2017, ahead of schedule, further facilitating the achievement of plateau performance in H1 2018.

Once more dynamic data from the wells is available, the Directors expect to have a better understanding of the ability and flexibility with the well and system design to increase production rates.

· Access to funding

The Group's Facility contains certain covenants (based on the ratio of indebtedness incurred under the term loan and revolving facility to EBITDA, finance charges to EBITDA, and requirement for liquidity testing). Prolonged low oil prices, cost increases and production delays or outages could further threaten the Group's liquidity and/or ability to comply with relevant covenants.

The Directors recognise the importance of ensuring medium term liquidity and in particular to protect against potential future declines in the oil price. EnQuest has a diversified funding structure and, following the Restructuring, it has a committed $1.125 billion Tranche A Term Loan and a further Tranche B $75 million Revolving Credit Facility and across the Facility $146 million remains available at 30 June 2017.

In addition, the maturity dates of the $650 million High Yield Bond and the £155 million Retail Notes have been amended to April 2022, with an option exercisable by the Group (at its absolute discretion) to extend the maturity date by one year and an automatic further extension of the maturity date to October 2023 if the Existing RCF is not fully repaid or refinanced by October 2020.

A further condition to the payment of interest on both the High Yield Bond and Retail Notes in cash is based on, amongst other things, the average prevailing oil price (dated Brent future (as published by Platts)) for the six month period immediately preceding the day which is one month prior to the relevant interest payment date being at least $65 per barrel; otherwise interest payable is to be capitalised.

The Group's latest forecast (Base case) which underpins this assessment takes account of the above actions and assumes that Kraken production rates will increase in line with updated expectations. The Base case uses an oil price assumption based on the forward curve of $52.2 per barrel forecast period in 2017, and $52.8 per barrel in 2018. This has been further stress tested under a plausible downside case (Downside case) by considering the impact of, amongst others, a 10% discount to the oil price forward curve and a 5% reduction in North Sea excluding Kraken production which is specifically risked in the Base case. The Directors consider the Base case and Downside case to be an appropriate basis on which to make their assessment.

The Group has historically reviewed farm down options and post Kraken start up, both the Base case and Downside case assume a farm down of Kraken and indicate adequate liquidity in the going concern period. Both cases also indicate breaches of covenants and would require waivers and/or consents as necessary.

The Directors also believe that a number of mitigating actions including other potential asset sales or 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. The Group has proactively applied for, and received, a waiver in advance of the end September covenant test. The Directors also believe that further waivers/and or consents would be forthcoming in order to ensure that the Facility remains available.

Nevertheless, there remain the risks that the Group is unable successfully to achieve potential asset sales or funding options and receive further waivers and/or consents. These risks represent material uncertainties that may cast significant doubt upon the Group's ability to continue to apply the going concern basis of accounting.

After making enquiries, assessing the progress against the forecast and projections and the status of the mitigating actions and actions to obtain waivers and/or consents referred to above, and notwithstanding the material uncertainties described above, the Directors have a reasonable expectation that the Group will be able to continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors therefore continue to adopt the going concern basis in preparing the financial statements.

EnQuest PLC

HALF YEAR GROUP STATEMENT OF COMPREHENSIVE INCOME

For the six months ended 30 June 2017

EnQuest PLC

GROUP BALANCE SHEET

As at 30 June 2017

EnQuest PLC

GROUP STATEMENT OF CHANGES IN EQUITY

For the six months ended 30 June 2017

EnQuest PLC

GROUP CASH FLOW STATEMENT

For the six months ended 30 June 2017

EnQuest PLC

NOTES TO THE GROUP HALF YEAR CONDENSED FINANCIAL STATEMENTS

1. Corporate information

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

The Group's principal activities are the exploration for, and extraction and production of hydrocarbons in the

UK Continental Shelf and Malaysia.

The Group's half year condensed financial statements for the six months ended 30 June 2017 were authorised for issue in accordance with a resolution of the Board of Directors on 7 September 2017.

2. Basis of preparation and accounting policies

The annual financial statements of EnQuest PLC are prepared in accordance with International Financial Reporting Standards ('IFRSs') as adopted by the European Union. The Group condensed financial statements for the six months ended 30 June 2017 have been prepared in accordance with IAS34 'Interim Financial Statements' as adopted by the European Union.

The Group half year condensed financial statements do 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 2016.

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

Statutory accounts for the year ended 31 December 2016, on which the auditors gave an unqualified audit report, have been filed with the Registrars of Companies. The audit report did not draw attention to any matters by way of emphasis and did not contain a statement under s498(2) or s498(3) Companies Act 2006.

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 pages 11 and 12.

Accounting policies

The accounting policies adopted in the preparation of the half year condensed financial statements are consistent with those followed in the preparation of the Group's financial statements for the year ended 31 December 2016. The standards adopted at 1 January 2017 did not have any impact on the results of the Group.

The Group has not early adopted any standard, interpretation or amendment that was issued but not yet effective. Other than the entitlements basis, which is still being investigated, the Group's evaluation of the effect of adoption of these standards is ongoing but it is not currently anticipated that either IFRS 9 or IFRS 15, which become effective on 1 January 2018, will have a material effect on the financial statements. The impact of IFRS 16, which becomes effective on 1 January 2019, is under review to determine the extent of any impact.

3. Segmental information

Segment information for the six month period is as follows:

(i) Adjustments and eliminations mainly includes the results from oil and foreign currency hedging, and oil marketing and trading activities.

Reconciliation of profit:

4. Re-measurements and exceptional items

(i) Fair value re-measurements include unrealised mark to market movements on derivative contracts and other financial instruments, where the Group does not classify them as effective hedges. It also includes the impact of recycling realised gains and losses (including option premia) out of "Re-measurements and exceptional items" and into "Business Performance" profit or loss. It also includes a $1.3 million gain in respect of the disposal of the Ascent Resources loan notes.

(ii) Impairments and write-offs include primarily a $79.6 million write down of tangible oil & gas assets. This has been triggered by the decline in the oil price since the year-end. For further details refer to note 7. 

(iii) "Other" mainly includes a charge of $4.0 million for the cancellation of crude marketing contract, and a US$0.8 million depreciation of the fair value uplift (2016: US$0.8 million). It also includes other items of income and expense which, because of the nature and expected infrequency of the events giving rise to them, merit separate presentation to allow shareholders to understand better the elements of financial performance in the year, so as to facilitate comparison with prior periods and to assess better trends in financial performance. In 2016 "Other" totalled $3.0 million before tax, and primarily included a $3.4 million reversal of a provision for contingent consideration which was no longer required following the results of the Eagle well drilled during the year.

(iv) Other tax exceptional items includes $6.7 million for the recognition of previously de-recognised tax losses due to the existence of taxable income outside the ring fence, together with $13.9 million for the impact on deferred tax of a revision to the balance of non-qualifying expenditure.

5. Revenue and other operating income

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:

7. Property, plant and equipment

(i) During the six months ended 30 June 2017, the Group's lease over the Kraken FPSO commenced (note 14).

(ii) The impairments have been triggered by the decline in the oil price since the year-end. Assets impaired include Thistle ($39.1 million), Dons ($18.0 million), Alma Galia ($20.9 million) and Alba ($1.6 million).

8. Intangible oil and gas assets

9. Share capital

The share capital of the Company as at 30 June 2017 was $208,639,000 (31 December 2016: US$208,639,000) comprising 1,159,398,871 Ordinary shares of £0.05 each (31 December 2016: 1,159,398,871 Ordinary shares of £0.05 each) and share premium of US$125,297 (31 December 2016: US$125,297).

10. Other financial assets and financial liabilities

(a) Balance sheet 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 IFRS13). There have been no changes to classifications from the prior year.

10. Other financial assets and financial liabilities (continued)

(b) Commodity contracts

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

Oil price hedging

During the six months ended 30 June 2017, no commodity derivatives were designated as effective oil hedges.

During the six months ended 30 June 2016, put options and swaps, which were designated as effective oil hedges, over a total of 4,500,000 barrels matured. Gains totalling US$125,356,000 were included in realised revenue in the income statement in respect of these matured contracts. A further gain of US$532,000, relating to the ineffective portion of hedges, was recognised within unrealised revenue.

Commodity derivative contracts at fair value through profit and loss

Commodity derivative contracts not designated as effective hedges are designated as 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, sold put options, commodity swap contracts and futures.

For the six months ended 30 June 2017 swaps over a total of 4.2 million barrels, and sold call options over 3.2 million barrels, either matured or were closed. Losses totalling of $6.3 million (30 June 2016: $14.3 million) were realised in revenue, including $10.5 million (30 June 2016: $15.2 million) of realised gains from the amortisation of option premiums received on the sale of call options. The premiums received are amortised into business performance revenue over the life of the option. Unrealised mark to market gains of $45.1 million (30 June 2016: losses of $9.1 million) were also recognised in exceptional revenue.

At 30 June 2017, the Group held swaps over 1.5 million barrels at an average fixed price of $55.37/bbl. These swaps had a fair value gain of US$9.9 million.

(c) Foreign currency contracts

During the six months ended 30 June 2017, the Group realised losses totalling $6.7 million on its first half chooser structure. These losses were recognised in 'business performance' cost of sales. Unrealised mark to market gains were recognised in exceptional cost of sales totalling $9.3 million. In addition, unrealised mark to market gains were recognised in exceptional cost of sales in respect of a new chooser option entered into during the first half of 2017. Under this contract, the counterparty can elect to sell £66 million to EnQuest at an exchange rate of US$1.1975:£1.0 or purchase 1.5 million barrels of oil at US$60/bbl. Based on current oil prices and exchange rates, the counterparty would currently choose to exchange currency, therefore the option has been presented with other foreign currency contracts.

In the six months ended 30 June 2016, realised losses totalling $51.5 million were recognised in cost of sales, of which $8.2 million was realised, and $43.3 million was unrealised.

(d) Income statement impact

Gains/(losses) on derivative financial instruments are recognised in the income statement as follows:

10. Other financial assets and financial liabilities (continued)

(e) Other receivables and liabilities

(i) As part of the agreement to acquire the PM8 asset in Malaysia, the Group agreed to carry Petronas Carigali for its share of exploration or appraisal well commitments. The discounted value of US$7.5 million has been disclosed as a financial liability (2016: US$7.4 million). Unwinding of the discount of US$0.1 million is included within finance expense for the period ended 30 June 2017 (30 June 2016: US$0.2 million).

(ii) Included in other liabilities is an accrued $12.0 million "waiver fee" payable to the Credit Facility lenders in relation to the restructuring of the facility in November 2016. The amount is payable by March 2018.

(iii) As part of the 2012 farm-out to the Kuwait Foreign Petroleum Exploration Company ("KUFPEC") of 35% of the Alma/Galia development, KUFPEC agreed to pay EnQuest a total of US$23.3 million over a 36 month period after Alma/Galia is deemed to be fully operational. US$3.3 million was received during the period ended 30 June 2017 and the remaining receivable, discounted to present value, had a carrying value of US$10.9 million at 30 June 2017 (31 December 2016: US$14.0 million). Unwinding of discount of US$0.1 million is included within finance income for the period ended 30 June 2017 (30 June 2016: US$0.3 million).

(iv) In August 2016, EnQuest agreed with Armada Kraken PTE Ltd ('BUMI') that BUMI would refund US$65 million (EnQuest's share being U$45.8 million) of a US$100.0 million lease prepayment made in 2014 for the FPSO for the Kraken field. This refund is receivable in instalments, with US$38 million receivable between February 2017 and February 2018, and the balance payable over a two-year period commencing three months after the date of first production from the Kraken field. Included within other receivables at 30 June 2017 is an amount of US$27.5 million (31 December 2016: US$43.5 million) representing the discounted value of EnQuest's share of these repayments. A total of US$16.7 million was collected during the period. Unwinding of discount of US$1.0 million is included within finance costs in the six months ended 30 June 2017.

Other receivables at 31 December 2016 also included $2.3 million representing the fair value of a convertible loan note from Ascent. This loan note was sold during the first half of 2017, realising a gain of $1.3 million.

The Group considers there to be no material difference between the fair values of financial instruments, interest bearing loans and borrowings and their carrying amount in the balance sheet.

11. 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.

12. Loans and Borrowings

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

(i) Includes capitalised interest totalling US$3.2 million (31 December 2016: US$0.2 million)

13. Bonds

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

(i) Includes interest totalling US$46.5 million (31 December 2016: US$27.5 million) which has been capitalised as part of the bond principal due to the oil price being below $65/bbl 

(ii) Includes interest totalling US$7.1 million (31 December 2016: US$nil) which has been capitalised as part of the bond principal due to the oil price being below $65/bbl

14. Obligations under finance lease

In June 2017, the Group's lease from Armada Kraken PTE Limited ('BUMI') of the FPSO for the Kraken field commenced. The lease has been assessed as a finance lease, and a $772.0 million lease liability and lease asset were recognised in the 30 June 2017 financial statements. The liability was calculated based on the present value of the minimum lease payments at inception of the lease. The lease liability is carried at $766.8 million as at 30 June 2017, of which $56.1 million is classified as a current liability. Finance lease interest of $1.7 million has been recognised within finance costs.

15. Provisions

Decommissioning provision

Additions during the period relate to estimated costs to decommissioning the additional sub-sea infrastructure put in place on the Kraken field during the six months ended 30 June 2017. 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.

Carry provision

Consideration for the acquisition of 40% of the Kraken fields was through development carries. A portion of the carry was dependent upon a reserves determination which took place in Q2 2016. The remaining $5.5 million carry outstanding at 31 December 2016 was paid in full during the six months ended 30 June 2017.

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 have not been recovered or deemed to have been recovered, EnQuest will pay to KUFPEC an additional 20% share of net revenue. This additional revenue is to be paid from January 2017 until the capital costs to first production have been recovered. To date no amounts have been paid to KUFPEC.

A provision has been made for the expected payments that the Group will make to KUFPEC. In establishing when KUFPEC has recovered its capital cost to first oil, the farm in agreement requires the use of the higher of the actual oil price, or US$90/bbl real, inflated at 2% per annum from 2012.

Contingent consideration

As part of the purchase agreement with the previous owner of the GKA assets, a contingent consideration was agreed based on Scolty/Crathes FDP approval and 'first oil'. EnQuest paid US$3 million in November 2015 as FDP approval was achieved in October 2015 and a further US$9 million was paid in the first half of 2017. A further US$8 million is due in the first half of 2018.

In addition, there is consideration due subject to future exploration success, for which a $5.3 million provision has been recognised (31 December 2016: $5.3 million).

Surplus lease provision

In June 2015, the Group entered a 20 year lease in respect of the Group's office building in Aberdeen with part of the building subsequently being sub-let with a rent free incentive. A provision has been recognised for the unavoidable costs in relation to the sub-let space.

16. Capital commitments and contingencies

At 30 June 2017 the Group had capital commitments of US$198.3 million (31 December 2016: US$267.3 million).

On 20 December 2013, the Group entered into a bareboat charter with Armada Kraken PTE Limited (Armada) for the lease of an FPSO vessel for the Kraken field. The lease commenced in June 2017 (refer note 14).

Contingencies

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

The Group is currently engaged in a dispute with KUFPEC, the Group's field partner in respect of Alma/Galia. KUFPEC has commenced a court action in the High Court of Justice claiming an alleged breach of one of the Group's warranties provided under the Alma/Galia Farm-in Agreement and seeking damages of US$91.0 million (the maximum breach of warranty claim permitted under the Alma/Galia Farm-in Agreement), together with interest. The court proceedings are currently stayed as the parties attempt to resolve the disputed issues. In the event that no agreement is reached and the court proceedings are recommenced, the Directors believe that a considerable period will elapse before any decision is reached by the courts.

The Directors consider the merits of the claim to be poor and the Group intends to defend itself vigorously. The Group has not made any provisions in respect of this claim as the Directors believe the claim is unlikely to be successful; and in any event the Directors believe the chances of an outcome exposing the Group to material damages are remote. There can, however, be no assurances that this claim will not ultimately be successful, or that the Group would not otherwise seek to enter into a settlement or compromise in respect of this claim, or that in the event of any such circumstances the Group would not incur costs and expenses in excess of its estimates.

The Group is also currently engaged in discussions with EMAS (represented by its trustees in bankruptcy), one of the Group's contractors on Kraken who performed the installation of a buoy and mooring system, in relation to the payment of approximately US$20.0 million of variation claims which EMAS claims is due as a result of soil conditions at the work site being materially different from those reasonably expected to be encountered based on soil data previously provided. The Group is confident that such variation claims are not valid and that accordingly such amount is not due and payable by the Group under the terms of the contract with EMAS. No formal court action has been commenced or threatened by EMAS. The parties are currently in discussions pursuant to the dispute resolution process under the contract.

17. Cash generated from operations